AGL Sales (Qld) Pty Limited v Dawson Sales Pty Ltd & Ors [2009] QSC 8

SUPREME COURT OF QUEENSLAND CITATION: AGL Sales (Qld) Pty Limited v Dawson Sales Pty Ltd & Ors [2009] QSC 8 PARTIES: AGL SALES (QLD) PTY LIMITED (ACN 121 177 740) Plaintiff V DAWSON SALES PTY LTD (ACN 087 886 913) First Defendant ANGLO COAL (DAWSON) LIMITED (ACN 100 155 342) Second Defendant MITSUI MOURA INVESTMENT PTY LTD (ACN 088 091 356) Third Defendant FILE NO/S: 10731 of 2007 DIVISION: Trial Division PROCEEDING: Hearing ORIGINATING COURT: Supreme Court Brisbane DELIVERED ON: 9 February 2009 DELIVERED AT: Brisbane HEARING DATE: 28, 29, 20, 31 July; 1, 4, 5, 6, 7, 8, 18, 19, 20, 21, 22 August; 1, 2, 3, 4, 5, September 2008 JUDGE: McMurdo J ORDER: 1. It is declared that: (a) The matters set out in the letter from the first defendant to the plaintiff dated 9 July 2007 do not constitute a Force Majeure Event as defined under the Gas Sale Agreement between the parties and do not entitle the first defendant to curtail the supply of gas (in whole or in part) under clause 14 of that Agreement; -- 1 of 43 -- 2 (b) The MDQ within the schedule to that Agreement of 18,000 gigajoules per day has not been amended by that letter of 9 July 2007, by the Notice purportedly issued by the first defendant to the plaintiff on 10 December 2007 or otherwise. 2. The plaintiff’s claim will be stood over for further submissions, if any, as to other relief according to the reasons for judgment. 3. The counterclaim is dismissed. CATCHWORDS: CONTRACT LAW-GENERAL CONTRACTUAL PRINCIPLES- CONSTRUCTION AND INTERPRETATION OF CONTRACTS-where the plaintiff purchases coal seam gas from defendant- where the defendant relies on force majeure clause to vary contract - where defendant did not apply good engineering and operation practice- whether geology constitutes force majeure event Gamlen Chemical Co (Australasia) Pty Ltd v Shipping Corporation of India Ltd [1978] 2 NSWLR 12 Energy Assets (Restructuring and Disposal) Act 2006 (Qld) COUNSEL: Mr P O’Shea SC with Ms S Brown for the Plaintiff Mr GA Thompson SC with Mr S Cooper for the defendants SOLICITORS: Brian Bartley & Associates as town agents for Gilbert & Tobin for the plaintiff Mallesons Stephen Jaques for the defendants [1] The plaintiff (“AGL”) purchases coal seam gas from the first defendant (“Dawson”). The gas is extracted from the Moura Coal Mine and is supplied to AGL under a written contract made in February 2003, which I will call the Agreement. Dawson contracted to supply the gas on behalf of the owners of the mine who are the second and third defendants. [2] The parties are in dispute as to the amount of gas which must be supplied under the Agreement. It provides for the supply of certain quantities, but it also provides that in some circumstances, described as a “Force Majeure Event”, Dawson may supply less gas. [3] Dawson says that it has encountered unforeseen difficulties in extracting gas at Moura, due to the particular geology of part of its field, and that the relevant events and circumstances constitute a Force Majeure Event. In July 2007 Dawson purported to temporarily reduce its supplies pursuant to the force majeure provisions of the Agreement. In December 2007 it purported to permanently reduce its supplies. -- 2 of 43 -- 3 [4] AGL says that for several reasons, these provisions have no operation in the circumstances which have occurred and that Dawson is in breach of the Agreement by failing to supply the quantities originally agreed. It claims that there has been no Force Majeure Event, that Dawson did not follow the requirements of the Agreement in giving its notices reducing its supplies and that in any case, by reason of the terms of the force majeure provisions, Dawson is precluded from relying upon the suggested Force Majeure Event because, in effect, it is Dawson’s fault that it has been unable to extract sufficient gas. That last matter has resulted in an extensive factual inquiry within this trial. Otherwise the questions are ones of the proper interpretation of the Agreement for which the relevant facts are largely undisputed. The Agreement [5] The Agreement was made in February 2003 between Energex Retail Pty Ltd as buyer and Dawson, then called Moura Sales Pty Limited, as seller. In 2006, AGL (then called Sun Gas Retail Pty Ltd), was substituted as the buyer.1 Energex and Moura Sales had made an earlier agreement (in 2000) for the supply of a relatively small quantity of gas, which was 2000 gigajoules per day, until May 2007. [6] The Agreement was for an initial term expiring on 1 January 2008, with options to the buyer to extend for a further five years and then a further two years. AGL has extended the term so that at present, it is to expire on 1 January 2013. [7] The quantity of gas to be delivered is to be no more than the “Maximum Daily Quantity” (or “MDQ”), as specified in a schedule to the Agreement. The agreed MDQ was initially 3,000 gigajoules per day, gradually rising to 11,000 per day in the 2006 calendar year, 16,000 per day in the next 16 months and from 1 May 2007, 2 18,000 gigajoules per day. [8] Within those upper limits, the quantity of the gas to be delivered is according to what is “nominated” by the buyer. Clause 10.1 provides that the buyer may nominate any quantity of gas for delivery on any day, provided that the seller is not obliged to deliver more than the MDQ. The buyer is to submit various forecasts (monthly, weekly and daily forecasts) of its requirements. The daily forecast, described as the “Daily Nomination”, is a notification of the buyer’s required amount of gas to be delivered on the following day. Dawson is permitted to deliver day by day a quantity within a certain range of the Daily Nomination. However, each month it must supply the sum of the Daily Nominations for that month. By cl 5.1.2, Dawson is not required to supply gas other than from that area defined as the “Gas Field”. Accordingly, it was not obliged to make up any shortfall by buying gas from other fields. [9] Regardless of what is nominated by the buyer, it is obliged to pay for a certain minimum quantity. In effect, the buyer has to pay for at least 80 percent of the aggregate of the MDQs for that month. [10] As it was likely that the buyer would require at least the quantity for which it was in any event obliged to pay, in practical terms Dawson knew that it had to supply, over 1 By notice given pursuant to the Energy Assets (Restructuring and Disposal) Act 2006 (Qld), published in the Gazette on 1 December 2006. 2 Coinciding with the expiry of the Agreement. -- 3 of 43 -- 4 time, at least 80 percent of the MDQ and that it had to be prepared to supply, if required, the whole MDQ. That affected, or should have affected, Dawson’s program for the exploration and extraction of this gas. The adequacy of that program and its implementation was a matter of considerable evidence and debate, to which I will return. [11] Clause 7.2 prescribes consequences for Dawson should it fail to deliver in any month the required quantity. In that event it is to pay a so called “Remedy Amount”, which is to be 40 percent of the contract price per gigajoule times the quantity of the shortfall. Clause 7.2 expressly provides that it has been the subject of specific negotiation and is: “intended to be liquidated damages that constitute the anticipated or actual loss or damage which would be incurred by [the buyer] due to failure of supply of Gas under this Agreement and not a penalty.” There is no argument here that this was a penalty. If Dawson is not relieved of its obligations to deliver the agreed MDQ as it claims, it accepts that AGL is entitled to liquidated damages calculated under this provision. The force majeure provisions [12] It is necessary to set out most of cl 14, which is as follows: “14. CURTAILMENT 14.1 Curtailment by Moura Sales for Force Majeure 14.1.1 Moura Sales may Curtail provision of Services if because of a direct Force Majeure Event, it cannot do, absolutely or in part, something it has to do under this Agreement (the “Affected Obligation”), when it has to do it. If a Force Majeure event occurs, Moura Sales must without delay issue a Notice to Energex setting out: a) what the Affected Obligation is; particulars of the event (to the extent Moura Sales knows them); b) its estimate of the reduction in Service capacity, in particular amending the MDQ under this Agreement over the Suspension Period; and c) its estimate of the duration of its inability to perform the Affected Obligation. 14.1.2 The Affected Obligation is suspended from the date the Notice is given until Moura Sales is able, after the exercise of all reasonable diligence, Good Engineering and Operating Practice and the employment of all reasonable means to remedy or abate the Force Majeure event as expeditiously as -- 4 of 43 -- 5 possible, to perform the Affected Obligation (this period is the “Suspension Period”). 14.1.3 A Force Majeure event or circumstances affecting the performance under this Agreement by Moura Sales shall not relieve Moura Sales of liability in the event, and to the extent, that the negligence or failure to use Good Engineering and Operating Practice by Moura Sales or the coal Mine Owners caused or contributed to its failure to perform under this Agreement or in the event of its failure to use all reasonable endeavours including the expenditure of reasonable sums of money and the application of proven technology to remedy the situation and to remove the event or circumstances giving rise to the Force Majeure event in an adequate manner with all reasonable despatch. 14.2 Suspension for Third Party Force Majeure … 14.3 Curtailment by Moura Sales due to Off-Specification Gas … 14.4 Curtailment by Moura Sales due to Maintenance … 14.5 Notice when the Suspension Period ends Upon completion of Maintenance activities under clause 14.3, or as soon as the Suspension Period under clause 14.1 ends, Moura Sales must, as soon as reasonably practicable, issue a Notice to Energex. The Suspension Period ends when Moura Sales, making reasonable efforts, is able to perform the obligation again, not when it gives the Notice. 14.6 Service Charges during Curtailment So long as Service is Curtailed under clauses 14.1, 14.3 or 14.4, Service charges will be calculated on the basis of the quantities of Gas actually delivered to Energex on a Day. 14.7 Affected Party must rectify the situation if possible During the Suspension Period Moura sales must make reasonable efforts to place itself in a position to perform the Affected Obligation (but Moura Sales is not obliged to settle -- 5 of 43 -- 6 any strike, lock out, boycott, work ban or other labour dispute or difficulty). 14.8 Termination If the Suspension Period lasts for more than 3 months, neither Party can terminate this Agreement, but either Party may, upon the expiry of that 3 months period, by Notice in writing to the other Party reduce the MDQ by the average quantity of Gas unable to be delivered or utilised on a Day over the Suspension Period and the Parties respective obligations under this Agreement will apply to that reduced MDQ for the remainder of the Term, effective immediately on Notification. The Authorised Officers of both Parties shall implement any necessary changes to MDQ pursuant to this clause by endorsing a variation to Schedule 2.” [13] It is cl 14.1 upon which the defendants rely. I have not set out cl 14.2: cl 14.2.1 is not relevant because it applies where a Force Majeure Event affects the ability of a customer of the buyer (now AGL) to take gas and cl 14.2.2 is not relevant because it applies where the buyer is unable to transport the gas which has been delivered to it. But the nature of these events indicates what is meant by a “direct Force Majeure Event” in cl 14.1.1. [14] The term “Force Majeure Event” is defined by the Agreement as follows: “'Force Majeure Event' means any event or circumstance, or combination of events or circumstances, not within the control of a Party, and which by the exercise of Good Engineering and Operating Practice, and seeking in good faith to comply with its contractual and other obligations by the expenditure of reasonable sums of money and the application of proven technology widely known to and generally available for use by persons in the gas industry, that Party is not able to prevent or (for the time being) overcome, including, without limiting the generality of the foregoing: (a) an act of God including, but not limited to, landslide, earthquake, flood, wash-out, lightning, storm and action of the elements; (b) strike, lock-out, ban or other industrial disturbance; (c) act of a public enemy, terrorism, war, sabotage, blockade or insurrection, riot or civil disturbance, arrests and restraints of rulers and peoples; (d) fire or explosion including radio-active and toxic explosion; (e) epidemic or quarantine; (f) order of any court or tribunal or the order, act or omission or failure to act of any government or Government Agency having jurisdiction; -- 6 of 43 -- 7 (g) failure to obtain or retain any necessary consent or approval of a Government Agency (despite timely and reasonable endeavours to obtain same); (h) unpredicted, sudden and material deterioration in productivity of more than one well or failure of wells, equipment or plant breakdown or failure that causes full or partial interruption of the delivery of Gas by Moura Sales under this Agreement; (i) the total or partial inability of a Party to receive or have quantities of Gas which are available for supply or delivery transmitted through the Queensland Gas Pipeline or the Moura Mine Pipeline because of an event of Force Majeure excusing non-performance by the owners or operators of the Queensland Gas Pipeline or the Moura Mine Pipeline, as the case may be, under a clause in a relevant gas transportation agreement; (j) shortages of labour or essential materials, failure to secure contractors and delays of contractors; (k) any breach of contract by, or an event of Force Majeure affecting a person contracting with Energex (‘Third Party Contractor’), which prevents Energex doing something that it has to do under this Agreement where Energex has taken all necessary, reasonable and practical action within a reasonable time to obtain performance of the Third Party Contractor’s relevant obligation whether by the Third Party Contractor or another person; or (l) any order, direction, or requirement under laws relating to Aboriginal heritage or native title; but does not include: (a) full or partial interruption of the delivery of Gas by Moura Sales due to failure or unpredicted and sudden deterioration in productivity of a single well, or the failure or breakdown of a single piece of equipment or plant, including compressors, pumps, Gas measurement equipment, and gathering lines; (b) full or partial interruption of the delivery of Gas by Moura Sales due to failure or unpredicted and sudden deterioration in productivity of a single dehydration unit if such failure or unpredicted and sudden deterioration could have been prevented by the exercise of Good Engineering and Operating Practice; -- 7 of 43 -- 8 (c) Energex’s loss of customers, loss of market share or reduction in demand for Gas; (d) a Party’s lack of funds or inability to obtain or use funds; or (e) changes in market conditions relevant to the transportation and/or the purchase and sale of Gas.” [15] Within that definition, and also within cl 14.1 itself, there is the expression “Good Engineering and Operating Practice”, which is defined as follows: “'Good Engineering and Operating Practice' means the practices, methods and acts engaged in or approved by a firm or body corporate who, in the conduct of its undertaking, exercises that degree of due diligence, prudence and foresight reasonably and ordinarily exercised by skilled and experienced operators engaged in the same type of undertaking under the same or similar circumstances and conditions, and includes complying with: (a) recognised Australian standards pertaining to that activity; and (b) manufacturers’ instructions and operating manuals; taking reasonable steps to ensure that: (a) adequate materials, resources and supplies are available at the necessary places under normal conditions associated with existing operations; (b) it has sufficient experienced and trained operating personnel available to undertake its responsibilities under this Agreement; (c) preventative, routine and non-routine maintenance and repairs are carried out to provide long term and reliable operation and are performed by knowledgeable, trained and experienced personnel using proper equipment, tools and procedures in accordance with the manufacturer’s recommendations; (d) appropriate monitoring and testing is carried out to ensure that the equipment will function properly under normal and emergency conditions; (e) equipment is operated and maintained in a manner safe to workers, the general public, and the environment; and (f) equipment is operated and maintained in accordance with any valid requirement established by legislation or regulation of any Governmental Agency having jurisdiction with respect to that equipment.” -- 8 of 43 -- 9 Dealings before the Curtailment Notice [16] Clause 14.1.1 required Dawson “without delay” to issue a Notice if it became unable to supply all or part of the required quantity of gas because of a Force Majeure Event. Dawson purported to issue such a Notice on 9 July 2007. However, for more than a year prior to then, Dawson had been unable to provide the required quantities. [17] Ms SG Deane is the Gas Commercial Manager for AGL and was previously in the same position for Energex Retail Pty Ltd (the original buyer under the Agreement). In November 2006 she became aware that Dawson had been consistently supplying less than the nominated amounts for most of the preceding 12 months. [18] On 14 November 2006, she met with Mr Trevor Stay, the General Manager Gas of the second defendant, to discuss the shortfall. He said, in effect, that Dawson had been experiencing drilling problems in a recently acquired area of land called Ridgedale because of the complex geology there, and that total production from the 15 wells drilled at Ridgedale had been approximately 2.3 terajoules (TJ) per day, when Dawson had expected about 7.5 TJ per day. (A terajoule is 1,000 gigajoules.) He provided an extensive explanation of those problems and of Dawson’s ideas to overcome them, as well as its proposal to acquire another area of land, known as Pretty Plains, for further drilling. He said that Dawson did not expect to produce the required MDQ until the end of 2007. [19] On 21 November 2006, Mr Stay sent to Ms Deane an email which attached Dawson’s production forecasts for 2007, according to which the expected supplies per day ranged from 13.8 TJ in January 2007 to 17.8 TJ in December 2007. For the first four months of 2007, for which the MDQ was 16 TJ per day, the forecasts ranged from 13.8 to 14.6. So depending upon what quantities were nominated by AGL, Dawson may have been able to supply what the Agreement required. However for June 2007, the forecast was 14.3 TJ per day, which was less than 80 percent of the (by then) MDQ of 18 TJ. Thereafter the forecasts were more than 80 percent but less than 100 percent of that MDQ. In summary, according to these forecasts, Dawson would be unable to perform its obligations if AGL required all of the gas to which it was entitled, or in June 2007 if AGL required no more than the minimum quantity for which it would have to pay in any event. Nevertheless no curtailment notice under cl 14.1 was then given. [20] On 23 February 2007, Mr Stay sent to Ms Deane another set of forecasts which extended through to June 2008. According to them, it would not be until March 2008 that the MDQ of 18 TJ could be met and production was expected to again fall below that figure in June 2008. [21] During the first half of 2007, Dawson furnished invoices which allowed credit for the Remedy Amounts claimed by AGL for the shortfalls from November 2005. [22] On 4 June 2007, Mr Stay emailed to Ms Deane a further set of forecasts according to which a daily quantity of 18 TJ would not be reached until July 2008. In a meeting that day, AGL’s representatives told Mr Stay that AGL would thereafter nominate the maximum MDQ of 18 TJ every day. [23] A further set of forecasts, to a similar effect, was given to AGL on 5 July 2007 for the purposes of a meeting that day, when Mr Stay explained to AGL’s -- 9 of 43 -- 10 representatives the defendants’ production difficulties, and in particular the difficult geology which had been encountered at Ridgedale. The Curtailment Notice [24] This was contained in a letter from Dawson to AGL dated 9 July 2007 which it is necessary to set out in full: “Gas Sales Agreement – Curtailment Notice Moura Sales Pty Limited ABN 97 087 886 913 (Moura Sales) hereby gives notice of Curtailment pursuant to clause 14.1.1 of the Agreement dated 28 February 2003 originally entered between Moura Sales and Energex Retail Pty Limited ABN 97 078 848 579 (Energex) as agent for Allgas energy Ltd ABN 54 009 656 446 (the Agreement). In accordance with clause 14 of the Agreement, Moura Sales advises: Affected Obligation The Affected Obligations are the obligations of Moura Sales under clause 5.4, clause 9.1.1, clause 9.3 and clause 10. Particulars of the event The particulars of the event, to the extent Moura Sales knows them, are: • In developing 15 new wells at Ridgedale, Moura Sales has encountered unpredicted and substantial geological problems; • The geological problems are most prominently severe structuring and faulting of lateral drill holes at various levels; • Structuring and faulting problems has caused both drilling difficulties and closing of lateral drill holes at Ridgedale; • Of 15 wells drilled at Ridgedale, 2 have been abandoned due to the extent of the difficulties encountered with the loss of the considerable cost of development of these wells; • Due to the drilling difficulties and closing of lateral drill holes, recovery of Gas from the Ridgedale wells has been materially less than was forecast prior to the commencement of development of these wells; • Attempts to resolve the impacts of structuring and faulting problems in accordance with obligations under the Agreement, have been ongoing but not successful to date and on current analysis may not be successful; -- 10 of 43 -- 11 • Wells which have failed to produce to date may well have to be abandoned depending on the outcome of ongoing measures to remedy within the terms of the Agreement; • The Ridgedale wells were developed following analysis of the Gas field and particularly the Hillview wells; • The Ridgedale wells were planned to come into production to meet projected contractual obligations; • The problems encountered in developing the Ridgedale wells were unexpected and unpredicted, particularly having regard to the geological information available to Moura Sales at the time; • Moura Sales has undertaken all stages of investigation and development of the Ridgedale wells in accordance with proven technology and practice as widely known to and generally available for use in the gas industry; • Moura Sales has expended approximately $15,000,000.00 in developing the Ridgedale wells; • For developed wells at Hillview, the Gas available for recovery is less than initially predicted due to unexpected difficulties in production; • Without limiting the above, the circumstances are such that there has been an unpredicted, sudden and material deterioration in productivity of more than one well and a failure of wells; • Moura Sales has exercised Good Engineering and Operating Practice at all times; • Moura Sales has sought to act in good faith to comply with its contractual and other obligations by the expenditure of reasonable sums of money and the application of proven technology widely known to and generally available for use by persons in the gas industry. The events and circumstances are beyond the control of Moura Sales. Moura Sales has not been able to overcome these events notwithstanding the exercise of Good Engineering and Operating Practice and seeking in good faith to comply with its contractual and other obligations by the expenditure of reasonable sums of money and the application of proven technology widely known to and generally available for use by persons in the gas industry. -- 11 of 43 -- 12 Estimate of reduction in service capacity Moura Sales estimates the reduction in Service capacity of 8,000 Gj per Day and in particular amends the MDQ to 10,000 Gj per Day over the Suspension Period. Estimate of duration Moura Sales estimates the duration of its inability to perform the Affected Obligations as 14 months from the date of this notice. We reserve all other rights, remedies and claims under the Agreement and this notice is in addition to and without prejudice to any such rights, remedies or claims.” [25] Before returning to that notice and the facts and circumstances to which it referred, it is convenient to complete the summary of the dealings which preceded the commencement of these proceedings. [26] On 16 August 2007, Ms Deane wrote to Anglo Coal requesting, in effect, further particulars of the curtailment notice. The second defendant replied on 22 August 2007, saying that her request was extensive, onerous and would take some time to answer. On 31 August 2007, it again wrote to Ms Deane saying that what she had requested did not have to be provided, but that nevertheless some information would be provided. On 6 September 2007, Ms Deane requested further information and a week later she and another representative of AGL were permitted to inspect some relevant documents held by the defendants. [27] On 28 September 2007, the parties reached an interim agreement. At that point three months had passed from the curtailment notice, so that if the notice had been validly given, the so-called Suspension Period by then would have extended for three months, entitling either party, according to cl 14.8, to reduce the MDQ by the average quantity of gas unable to be delivered over that period. By this interim agreement, Dawson agreed not to act under cl 14.8 within the next month. On 19 October 2007, a further interim agreement was reached, by which Dawson was not to serve a cl 14.8 notice prior to 1 April 2008, provided that either party might terminate this interim agreement on four weeks notice. On 9 November 2007, Dawson terminated that interim agreement and on 10 December 2008 it gave a notice purportedly under cl 14.8 to permanently reduce the MDQ to 9.116 TJ/day, which was the agreed MDQ of 18 TJ/day less the average quantity of gas which could not be delivered during the Suspension Period, which was said to have been 8.884 TJ/day. [28] The defendants’ case is that the agreed MDQ was thereby varied. AGL’s case is that, for many reasons, the MDQ has remained at 18 TJ. AGL’s first argument is that there was not a Force Majeure Event, to which I now turn. The alleged Force Majeure Event [29] The Curtailment Notice described the Force Majeure Event in several ways and in broad terms, rather than identifying anything which was said to be a single occurrence. In the pleadings in this case, the defendants do not specify what it was which constituted the Force Majeure Event. In their final submissions, the defendants put the matter in these terms: -- 12 of 43 -- 13 “76. The Defendants’ primary submission is that the failure of more than one well (subparagraph (h)) was a sufficient event or circumstance to satisfy the definition of a Force Majeure Event. 77. Alternatively, the definition of Force Majeure Event is satisfied by: (i) the failure of more than one well and/or the unpredicted, sudden and material deterioration in productivity of more than one well; (ii) the presence of low angle thrust faulting, shearing of the coal within the seams and/or the presence of coal fines within the seams, either alone or in combination with the events and circumstances described above; or (iii) encountering low angle thrust faulting, shearing of the coal within the seams and/or the presence of coal fines within the seams, either alone or in combination with the events and circumstances above.” [30] When the Agreement was made in 2003, Dawson was extracting gas from a parcel of land within the Moura mining lease called Hillview. But wells have a limited life, at least because there is only so much gas which can be extracted from any one location. And having regard to the increasing MDQ during the life of the Agreement, Dawson well knew that it would have to drill wells beyond Hillview in order to meet its commitments. [31] The land called Ridgedale is alongside Hillview. Dawson commenced exploratory work on Ridgedale at the end of 2004. The first of the production wells on Ridgedale was drilled by 13 June 2005 and began to produce gas from December 2005. Dawson attempted to drill 15 production wells in Ridgedale. Two of them, being the wells numbered RG (Ridgedale) 3 and RG 13, did not produce any gas. As I will discuss, five of them produced some gas but their production had ceased by the time of the Curtailment Notice in July 2007. The other wells were still producing then, although in each case the production had been less than Dawson had expected. So each of these 15 wells was either never productive or was less productive than Dawson had forecast. In each case the problem is said to have been the difficult and unforeseen geological conditions which were encountered. [32] The defendants have given only this one Curtailment Notice, according to which the Force Majeure Event was constituted by many occurrences at different times over a period which, on any view, extended for more than a year. In the same way, the defendants’ case according to their final submissions relies upon the entirety of what happened at Ridgedale throughout that period. -- 13 of 43 -- 14 [33] As I will discuss, for at least some of the Ridgedale wells, there was at least in one sense a failure of the well and for others, there was a deterioration in productivity although not one which could be described as sudden and unpredicted. But from the several failures of wells it does not follow that there was a Force Majeure Event, within para (h) of the definition or otherwise. The defendants’ case is premised upon an interpretation of the definition and of cl 14 which, in my conclusion, should not be accepted. [34] According to cl 14.1.1, a Force Majeure Event is something which “occurs”. It may be an event or circumstance, or a combination of them, but there must be an occurrence, and necessarily, one within the life of the Agreement. So the mere geology of Ridgedale or of some location within it could not of itself constitute the Force Majeure Event. [35] The defendants’ case, like the Curtailment Notice, does not attempt to identify any point in time when there was this occurrence of a Force Majeure Event. Rather, their case is that by the time of the Curtailment Notice, a Force Majeure Event had occurred by a combination of events and circumstances over a period. On their case, no distinct occurrence must be demonstrated, because a Force Majeure Event might be constituted by considering together a sequence of distinct happenings. In this, the defendants would appear to heavily rely upon that part of the definition which refers to a “combination of events or circumstances”. [36] A further element of the defendants’ argument is that cl 14 does not require the Force Majeure Event to have an immediate impact on the delivery of gas. On their case, although there is a required causal connection between the Force Majeure Event and Dawson not being able to supply the required quantity of gas, the cause and the effect may be far remote in time from each other. And they argue that Dawson is entitled to wait to the point in time when there is that effect upon its supplies before giving the Curtailment Notice. Indeed, the defendants’ argument goes further, in contending that Dawson is not required even at that point to give a Curtailment Notice. [37] In my view, what is relied upon as a Force Majeure Event must be something with an immediate effect upon Dawson’s capacity to supply and thereby upon its then performance. Clause 14.1.1 provides that “if a Force Majeure Event occurs [Dawson] must without delay issue a [Curtailment] Notice”. Contrary to the defendants’ argument, this could mean only that the notice is to be issued without delay from the occurrence which is said to constitute the Force Majeure Event. The defendants’ argument does not identify any other point in time from which the presence or absence of delay could be assessed. The Curtailment Notice is to contain Dawson’s “estimate of the reduction in Service capacity, in particular amending the MDQ under this Agreement over the Suspension Period”. Clause 14.1.2 provides that “the Affected Obligation is suspended from the date the notice is given until [Dawson] is able…to perform the Affected Obligation”. As the defendants apparently accept, the “Affected Obligation” in this context is Dawson’s obligation to supply certain quantities of gas.3 The parties have thereby agreed that Dawson is relieved from having to supply what had been agreed, immediately from 3 Schedule 1 to the Agreement defines “Affected Obligation” as having “the meaning ascribed to it in cl 14.1.” -- 14 of 43 -- 15 its giving the Notice, which is to be given without delay from the occurrence of the Force Majeure Event. [38] There is an evident commercial purpose in requiring Dawson to give its Curtailment Notice without delay from the occurrence. The buyer would wish to know of the occurrence and of the extent and likely duration of its impact so that it could seek to rearrange its business on the expectation of a shortfall in supply. Yet the defendants argue that there is no obligation on Dawson to give a Curtailment Notice on the occurrence of a Force Majeure Event, or otherwise to inform the buyer of it. They argue, in reliance upon the words “Moura Sales may curtail provision of services”, that Dawson is not required to “Curtail”, which they say means “invoke the procedure to implement its rights under the [Agreement] to interrupt Service”. For that they rely upon another definition within Schedule 1 of the Agreement, by which: “Curtail” or “Curtailment” means Moura Sales’ procedure to implement its rights under this Agreement to interrupt Service: (a) because of a Force Majeure Event…” However, on any view of the Agreement, the effect of a Force Majeure Event must be disabling: it must have the result that Dawson cannot, absolutely or in part, perform the Affected Obligation, i.e. the obligation to supply gas. There is no choice which Dawson is given to reduce or not to reduce the gas supply. This is because cl 14 is engaged only where the agreed quantity cannot be supplied. The words “[Dawson] may Curtail provision of Services” are not a reference to alternative courses open to Dawson, but instead mean that Dawson is permitted to not supply that which it cannot supply because of the Force Majeure Event. The absence of such a discretion is confirmed by the mandatory terms of the second sentence of cl 14.1.1, whereby Dawson must without delay issue a notice if a Force Majeure Event occurs. [39] This requirement of an immediate effect of the Force Majeure Event is illustrated by para (h) of the definition of the term, which refers to the deterioration in productivity of more than one well or the failure of wells causing a “full or partial interruption of the delivery of Gas…” The same point appears from the specific exclusions the second of the sub-paragraphs (a) and (b) in the definition, each of which describes a case of such full or partial interruption of delivery. So the relevant cases of deterioration in productivity of wells are where the deterioration is “sudden” and “material”, because a gradual or immaterial decline would not “interrupt” the delivery of gas. [40] In aggregating the effects of various things occurring over this period in Ridgedale, the defendants rely upon that part of the definition of Force Majeure Event by which it may be constituted by a “combination of events or circumstances”, as well as by a particular event or circumstance. So on their case, for example, the effect of one well failure is to be aggregated with the effect of another failure which perhaps occurred many months earlier. The same applies to distinct instances of the unpredicted, sudden and material deteriorations in productivity of two wells. This argument has a tension with the way in which the parties, by this definition, have plainly agreed to distinguish the failure or deterioration of a single well from that of more than one well. What is expressly excluded is: -- 15 of 43 -- 16 “(a) [The] full or partial interruption of the delivery of gas by [Dawson] due to failure or unpredicted and sudden deterioration in productivity of a single well…” But what is expressly included is: “(h) [The] unpredicted, sudden and material deterioration in productivity of more than one well or failure of wells…that causes full or partial interruption of the delivery of gas by [Dawson] under this Agreement.” [41] On the defendants’ case, for example, the effect of one well failure is to be considered together with the effect of another well failure, because those distinct failures are said to represent a combination of events, although the parties have agreed that neither event of itself could constitute a Force Majeure Event. [42] In my view, this argument involves a misinterpretation of the express inclusion within para (h). What is referred to there is the failure of wells rather than the failures of wells. Each well failure is an event but where there are two failures, it must be the combined effect of those events which causes an “interruption of the delivery of gas”. Suppose one well fails causing a partial interruption in delivery: according to the express exclusion, there would be no Force Majeure Event. Suppose then that another well fails some months later, causing its own partial interruption of the delivery of gas: again, of itself, that would not be a Force Majeure Event. In a sense the two failures may have had an aggregate effect (although Dawson may have overcome that effect by production from other wells before the second failure). But there is not an interruption which has been caused by them in combination. There have been two distinct interruptions, some months apart, and the second interruption would not in any sense have been caused by the first well failure. In other words, to fall within the specific inclusion within para (h), what must occur for several wells, by a failure or an unpredicted, sudden and material deterioration in productivity, are events which operate in combination to cause a certain interruption of the delivery of gas. [43] The generality of this Curtailment Notice, and of the defendants’ submissions as to what constitutes the Force Majeure Event, results from these flaws in their case. They have failed to identify a certain occurrence, in the sense of an event or circumstance, or events or circumstances acting in combination, having an immediate consequence upon Dawson’s performance at that point in time. Of course in theory, there could be a series of Force Majeure Events constituted by a series of occurrences over a period. But what was agreed was that with each occurrence, Dawson was to issue without delay a Curtailment Notice, and that the extent of Dawson’s obligation to supply would then be altered according to the effect of that occurrence upon Dawson’s capacity. The defendants have not sought to put their case in those terms. Had they attempted to do so, it would be yet clearer that they are relying upon distinct failures or deteriorations of wells which, case by case, are expressly excluded by the definition. [44] In particular, the defendants have not sought, in the alternative, to prove that a certain event or events at Ridgedale has or have had an effect on Dawson’s capacity which could be measured. Their case is simply that if a Force Majeure Event has occurred, Dawson is relieved of any liability for the entire shortfall in its supply, i.e. the difference between its actual supply and 18 TJ/day. They argue that this -- 16 of 43 -- 17 comes from the proper interpretation of cl 14.8, which allows either party to permanently reduce the MDQ by “the average quantity of Gas unable to be delivered…on a Day over the Suspension Period…” This interpretation could have perverse results and cannot be accepted. In the context of cl 14 and the Agreement as a whole, the gas which is “unable to be delivered” is that which, because of the Force Majeure Event, cannot be delivered. This is consistent with cl 14.1.1, by which the MDQ is to be amended during the Suspension Period by Dawson’s estimate of the reduction in its “Service capacity”. In its Curtailment Notice, Dawson simply attributed all of the difference between its estimated capacity of 10 TJ/day and the MDQ of 18 TJ/day to the entirety of its experience over nearly two years at Ridgedale as well as to what was there asserted to have been a recovery from “developed wells at Hillview [being] less than initially predicted due to unexpected difficulties in Production”. (That particular was not argued in the defendants’ case here. And, as I will discuss, their argument was that “Hillview was a successful production field producing only slightly less gas than forecast”.4 ) In their case, the defendants have not attempted to identify an occasion which represents an interruption in the delivery of gas. Nor have they sought to prove the extent of the diminution in Dawson’s capacity from, in aggregate, the failures of certain wells; other than perhaps by reference to Dawson’s forecasts of production. Even then, these alleged failures would not account for the 8 TJ/day by which the MDQ was purportedly reduced by the Curtailment Notice. [45] As the defendants concede, the burden is upon them to prove that there was a Force Majeure Event, because the absence of that is not an element of AGL’s right of action, which comes from Dawson’s promise to supply gas in quantities which it has not delivered. In the same way, it is the defendants who must prove the extent to which a Force Majeure Event has relieved them from their obligation to supply the agreed MDQ. If, contrary to my conclusion, the defendants have proved a Force Majeure Event, they have failed to discharge that second onus. In the course of final submissions, when I asked the defendants’ counsel what the outcome should be were I to find that there was a Force Majeure Event constituted by what happened to certain number of these wells, the response was I should re-list the matter for further submissions. But that ignores the evidentiary gap in the defendants’ case, reflecting the level of generality at which they have put their case in and from the Curtailment Notice. [46] There is a further and important point as to para (h). The “deterioration in productivity” to which it refers involves a comparison of its actual productivity at two points in time. It does not involve a comparison of its forecast productivity with its actual productivity. Much of the evidence involved an investigation of Dawson’s exploration and planning, and of the reliability of various forecasts of production from Ridgedale. Undoubtedly each of these 15 wells was, at the least, less successful than Dawson had expected. But that disparity does not constitute a Force Majeure Event, and in particular it does not constitute an event within para (h) of the definition. It is a change to the actual productivity and thereby to the level of actual production which results in an interruption of the delivery of gas. The Ridgedale Wells [47] I turn now to the history of each of the 15 wells at Ridgedale. 4 Defendants’ written submissions, para 179. -- 17 of 43 -- 18 [48] RG 1 began producing on 22 December 2005. Its output gradually increased to about 0.57 TJ/day in March/April 2006, after which it gradually declined. On 1 January 2007 it produced 0.399 TJ. It continued to decline in 2007, at least until the end of June 2007. On 29 June 2007 its production was 0.30 TJ and on subsequent days but prior to 9 July 2007, its output fell somewhat. It was 0.255 TJ on 30 June, 0.206 TJ on 1 July, 0.14 TJ on the next day before producing 0.20 TJ on 3 July. It was down to 0.16 TJ on 6 July and it was about the same through 9 July 2007 when it produced 0.15 TJ. Curiously it appears to have recovered, at least by late July (there being no evidence of its output from 9 to 24 July 2007). There was certainly then a deterioration in productivity, which is indicated by a decrease in production from about 0.3 TJ/day on 29 June to about 0.15 TJ/day on 9 July 2007. I accept that this represents a decrease in the well’s productivity. I am not satisfied that this was a sudden and material decrease in productivity which interrupted, in part, the delivery of gas in the sense of para (h). The defendants’ case about RG 1, as with many other wells, is that the well always produced less, and its “peak” period was shorter, than had been forecast. This deterioration occurred more than a year after the well’s peak. [49] RG 2 experienced no failure or sudden deterioration in productivity prior to the Curtailment Notice on 9 July 2007. It began production on 15 January 2006, and by the following month it was producing in the vicinity of 0.75 TJ/day. In March 2006 it had reached its peak of 0.785 TJ, after which it declined, but in my view not suddenly. Its production was low for some days in June and on 2 August 2006, but there were several other days in which there was no production which was apparently due to maintenance or what are described as “workovers”. Its production by the end of August was close to where it had been in May 2006 and thereafter it experienced what I see as a gradual decline, falling to 0.47 TJ on 1 January 2007 and 0.359 TJ on 9 July 2007. [50] It is common ground that RG 3, RG 11 and RG 13 did not produce any gas. The defendants say that this constitutes a failure of those wells “on any view” for the purposes of para (h) of the definition. AGL argues that they were not failures in that sense, because to be within para (h), they had to cause a full or partial interruption of the delivery of gas. There was no interruption in the flow of gas because nothing flowed from these wells. I accept AGL’s submission. From that it would also follow that none of these failures was a failure within the specific exclusion in para (a) of the definition. In the case of RG 11, however, despite the parties agreeing that it was never productive, there is evidence that there was some gas produced, although in very small quantities, on 7 and 13 October 2006 and on six days in January 2007. The highest daily quantity was 0.039 TJ on 31 January 2007 after which no gas flowed from it. The point at which RG 11 could be said to have failed is not clear, but in any case it is not said to have occurred simultaneously with the failure of another well. Nor is any event with that well shown to have interrupted the delivery of gas. [51] RG 4 began to produce gas in March 2006. It produced nothing from 26 April to 18 June 2006 and with the exception of a few days in late June and early July 2006, it continuously produced, day by day, until and beyond the date of the Curtailment Notice. Its most productive day was 31 October 2006 when it produced 0.454 TJ. On 9 July 2007 it produced 0.2166 TJ, and for most of the period between those dates it produced in a range from 0.2 to 0.3 TJ. This well was not a failure either in -- 18 of 43 -- 19 any ordinary sense or in the sense of para (h). Nor was there any sudden decline in productivity in this case. [52] RG 5 commenced production at the end of December 2005 and by late February 2006 it was producing more than 0.7 TJ/day. After that there was some decline in its production but nothing remarkable until 30 July 2006, when its production fell to 0.205 TJ on 30 July from 0.464 TJ on the previous day. Thereafter its production was a little more or less than 0.02 TJ/day, decreasing to 0.130 TJ on 30 December 2006. It increased slightly on the following day but was then unproductive until 5 February 2007, when it produced 0.192 TJ. That was its last production. The plaintiff concedes that this well was a failure. As such, it could be regarded as having failed either after 5 February 2007 or alternatively at the beginning of January 2007. [53] Very little was produced from RG 6. According to exhibit 107.234, its production began on 30 March 2007 at 0.067 TJ and on one occasion it exceeded 0.1 TJ (30 April 2007). Its production then declined, although not suddenly at least to 13 May 2007, after which there was no production for the rest of that month. In early June there were some days of very low figures but nothing was produced after 11 June 2007. It could be regarded as a failed well from early May 2007 when it was producing no more than 0.08 TJ/day. [54] There was some but little production from RG 7. It began on 2 June 2006 and there was continuous production for about a month, reaching a peak of 0.36 TJ on 2 July 2006. It fell to 0.25 TJ on 3 July and then 0.15 TJ on 4 July 2006. From then there were only a few days of further production: 1 September 2006 (0.30 TJ), 11 September 2006 (0.308 TJ), about six days in February 2007, (at most 0.003 TJ/day) after which it was in continuous production from late March 2007 until 22 May 2007 (rising to more than 0.30 TJ in several days in May). After 13 May 2007 (0.32 TJ) its production decreased to 0.112 TJ on 22 May before it ceased. In this way it appears to have had effectively two lives and could be thought to have failed in July 2006 and again on about 23 May 2007. [55] RG 8 began producing in about June 2006. By the following month it was producing in the range of 0.2 to 0.3 TJ, after which there was some decline, although not sudden, before an increase by the end of that year. During 2007 it consistently yielded more than 0.3 TJ until around 20 June when there was some decline. It was 0.2516 TJ on 9 July 2007. There was no sudden decline in productivity in the case of this well, at least prior to the date of the Curtailment Notice and the decline in 2006 had been reversed by then. Nor could it be regarded as a failure in any sense although, of course, the actual production was less than had been forecast. [56] RG 9 began producing in June 2006. Its rate of decline corresponded with the forecast, although the level of production was much lower. After a peak of 0.43 TJ on 27 July 2006, its output gradually declined, amounting to 0.222 TJ on 9 July 2007. There was no sudden deterioration in productivity and nor was there a failure in the case of this well. [57] RG 10 began producing in about October 2006. There was one day of high production (8 November 2006: 0.46 TJ) after which its output was usually lower than 0.1 TJ as it had been prior to that particular day. For a few days in early -- 19 of 43 -- 20 January 2007, it was between 0.1 TJ and 0.152 TJ before falling again. It continued to produce but at consistently very low levels. It was still in production on 9 July 2007 (0.114 TJ), so it had not failed as of the date of the Curtailment Notice. Nor was there a sudden decline in productivity. Its figures in July 2007, although lower than those for May 2007, were generally higher than they had been for most of its life. Unfortunately within the actual production records in evidence in exhibit 107.221, there are no entries for June 2007, making it yet more difficult to conclude that the July figures represent some sudden and material deterioration in productivity. [58] RG 12 was a relatively successful well for Ridgedale. It produced from about the end of August 2006, rising to 0.508 TJ on 20 November 2006 before declining but not suddenly. For a few days in March 2007 it was again close to 0.5 TJ. On 28 May 2007 it produced 0.4292 TJ but its production in June 2007 was relatively poor and it was not in production from 3 through 8 July 2007. On the date of the Curtailment Notice it produced 0.222 TJ. As it was in production at the date of the Curtailment Notice it was not a failure and nor from the June production is there demonstrated a sudden deterioration in productivity. [59] RG 14 began producing in January 2007. There were several days of no output, including in a period from 24 February through 20 March. But then, with the exception of the odd “down” day, it produced between 0.1 TJ and 0.2 TJ in April, increasing in May towards 0.25 TJ before declining but not suddenly in June. On 9 July 2007 it produced 0.1924 TJ. There was no failure or sudden deterioration in this case. [60] RG 15 began producing in October 2006 and reached a peak of 0.377 TJ later that month. From then it declined to less than 0.1 TJ by the end of November 2006. It was unproductive from 22 February through 1 September 2007, with the exception of 20 and 21 March 2007. It was revived in September 2007 but I accept that it should be characterised as a failure as at the date of the Curtailment Notice, because it had not produced for some months prior to then. [61] The result is that there was no well which experienced a deterioration in productivity which was “sudden”, in the sense used in para (h), which is that it must happen so quickly that it interrupts the delivery of gas. [62] To the extent that the point in time of a failure of a well can be identified, in no case does it coincide with another well failure. There were distinct failures, not involving a “failure of wells” within para (h). Further, as I have discussed, RG 3 and RG 13 were never productive so on no view was there an interruption of the delivery of gas caused by their abandonment. Nor is it demonstrated that any of RG 5, RG 6, RG 7, RG 11 or RG 15 was a failure which caused a (partial) interruption of delivery. In each of these cases of course, had the well not failed, more gas would have been delivered. But that is not to say that the failure was such as to interrupt the delivery of gas. [63] There is an alternative argument for the defendants, which is that the Force Majeure Event was constituted by the “encountering of low angle thrust faulting, shearing of the coal within the seams and/or the presence of coal fines within the seams…” As counsel for the defendants said in their opening, these conditions were probably “encountered” in the course of the lateral drilling of wells. -- 20 of 43 -- 21 However, this was prior to the production, if any, from the well and the event or circumstance constituted by that encountering lacked the immediate impact upon the delivery of gas which is required in this context. The relevant occurrence in this sense, well by well, was simply the drilling of ground where the relevant conditions were likely to later impede the recovery of gas, although the defendants were not to know that at the time because, as their case emphasised, drilling problems were not necessarily an indication of future production problems. [64] The defendants argue that what happened with these wells could be within the more general terms of the definition if not within the specific inclusions in para (h). However, the terms of the specific inclusions and exclusions are to be considered in interpreting the more general terms of the definition and also cl 14. As discussed, the defendants must still identify a particular occurrence and one which had an immediate effect upon the delivery of gas. So the gradual failure or simply the poor performance of a well does not have those features. And it would be curious if the gradual failure of a poorly performing well could constitute a Force Majeure Event, when the parties have agreed that a failure which has an immediate impact, by causing an interruption in the delivery of gas, should not be able to be relied upon by the seller because of the specific exclusion within the second para (a) of the definition. [65] The outcome is that at least for these reasons, and quite apart from questions of Good Engineering and Operating Practice, the matters relied upon by the defendants did not constitute a Force Majeure Event and did not entitle Dawson to temporarily or permanently alter the MDQ. The question is not whether in all the circumstances it is reasonable that the defendants should be held to the promise to deliver the agreed quantities. They did not agree that they were only to make reasonable endeavours to supply certain quantities. By the Agreement, the risk that Dawson’s attempts to recover gas from then unexplored land might prove to be more difficult than had been experienced was one which the defendants assumed. In particular, they generally assumed the risk that from time to time, a well could fail or suddenly deteriorate, or that the conditions which were encountered would affect the rate at which gas was extracted. [66] It follows that the plaintiff, AGL, is entitled to succeed. This makes it unnecessary to consider AGL’s arguments as to the deficiencies of the Curtailment Notice, assuming that there had been a Force Majeure Event, but some matters should be noted. [67] AGL argued that the Curtailment Notice was given too late, having regard to the requirement in cl 14.1.1 that it be given without delay from the occurrence of the Force Majeure Event. Because of the way in which the defendants put their case, the date of occurrence of the Force Majeure Event for which they contended is not easy to identify. If the failures of wells were regarded as, in total, the Force Majeure Event, then the last of them failed on 23 May 2007. Even the period between then and 9 July 2007 would, in my view, constitute a delay. Alternatively, if there was a Force Majeure Event in the encountering of the geological conditions, then as already noted, the defendants agreed that this had occurred at least by the time the first laterals were drilled in June and July of 2005, so that clearly there was a delay of some two years. In truth, the giving of the Curtailment Notice did not coincide with any particular event but instead was likely to have been prompted by AGL’s announcing that it would nominate the MDQ of 18 TJ for each and every -- 21 of 43 -- 22 day. On any view then, if there was a Force Majeure Event, Dawson did not give the Curtailment Notice without delay from its occurrence, as required by cl 14.1.1. It is unnecessary that I discuss the respective arguments as to whether, on the proper interpretation of the Agreement, that would make the Curtailment Notice ineffective or whether it would provide only a right to damages for any loss from that breach. [68] AGL also argued that the Curtailment Notice was ineffective because it failed to comply with the requirement in cl 14.1.1 that it set out “particulars of the event”. It is difficult to usefully comment about that because of my conclusion that there was no Force Majeure Event, except that some general points may be noted. The first is that the content of this requirement must be affected by its purpose, which is to inform AGL of information relevant to its consideration of what it should do in response to the shortfall in supply. There would be a question of degree involved yet, at times, AGL’s position seemed to be that Dawson had to set out everything which could be said of the event, rather than only so much as would provide sufficient information to enable AGL to understand what had occurred in order to consider its own position. Nevertheless, the Curtailment Notice referred to some wells as having failed and to others as having deteriorated in productivity, without saying how many wells or which wells were involved in either category. In addition it was asserted in the Curtailment Notice that the recovery from developed wells at Hillview had been less than initially predicted “due to unexpected difficulties in production.” That matter, which was not part of the defendants’ case here, failed to identify the extent of that suggested problem and was particularly uninformative. Again it is unnecessary to resolve whether a lack of particularity would deny the Curtailment Notice of any effect. [69] Thirdly, AGL argued that Dawson had not set out in the Curtailment Notice its estimate of the reduction in Service capacity, in breach of cl 14.1.1(b). As I read the Curtailment Notice, it does provide an estimate of that reduction at 8,000 gigajoules per day. On its face then, the Notice did meet this requirement, although, of course, it would be a different matter to consider whether that estimate was at all realistic. The outcome at Ridgedale: Was it preventable? [70] There were extensive factual issues as to whether the problems at Ridgedale could and should have been prevented or overcome. Should this matter go further I now turn to them. Who bears the onus? [71] Most of the trial was taken up with evidence and argument about whether Dawson acted according to Good Engineering and Operating Practice as that term was defined in the Agreement. That question could arise in the consideration of whether there was a Force Majeure Event as defined. It is also relevant under cl 14.1.3, if considering whether, and the extent to which, the defendants could rely upon the Force Majeure Event for which they contend. [72] The term Force Majeure Event is defined generally together with certain specific inclusions and exclusions. On the defendants’ principal argument that there was a Force Majeure Event constituted by a number of well failures within the specific inclusion in para (h) of the definition, they argue that they need not also bring their case within the general words at the commencement of the definition. They point to the specific inclusion in para (k) and the exclusion within (the second) para (b), each -- 22 of 43 -- 23 of which contains its own qualifications which would be unnecessary if the conditions within the general words had to be satisfied. In particular, the exclusion in para (b) is for a failure or unpredicted and sudden deterioration in productivity of a single dehydration unit, if that could have been prevented by the exercise of Good Engineering and Operating Practice. That qualification would be unnecessary if the general terms of the definition had to be satisfied also. Upon this argument for the defendants, questions of Good Engineering and Operating Practice and similar questions involving some fault on Dawson’s part would be considered only in relation to cl 14.1.3. [73] AGL argues otherwise. It says that a failure of wells or the deterioration in productivity of more than one well, which is within the specific terms of para (h), must nevertheless satisfy the general words of the definition. The defendants’ argument appears to be the better one, but it is unnecessary to resolve this question of construction within this judgment, because of my conclusions that for other reasons there was no Force Majeure Event. It is appropriate still that I make findings as to whether the case is within the general words of the definition, if AGL’s argument is correct or if the defendants’ alternative arguments as to what constituted the Force Majeure Event were to be upheld. [74] As the defendants accept, they bear the onus of proving that there was a Force Majeure Event. Accordingly, if the general words of the definition must be satisfied, the defendants must prove that the relevant occurrence was: • not within Dawson’s control • something which Dawson was not able to prevent or (for the time being) overcome by exercising Good Engineering and Operating Practice and seeking in good faith to comply with its contractual and other obligations by the expenditure of reasonable sums of money and the application of proven technology widely known to and generally available for use by persons in the gas industry. In the events and circumstances here, the question is effectively the second of those matters. In other words, if the defendants could prove that Dawson, with that exercise, expenditure and application, could not prevent or overcome the relevant occurrence, then they would also have proved that the occurrence was not within Dawson’s control. [75] Clause 14.1.3 would apply only if there was a Force Majeure Event. It provides that Dawson would not be relieved of liability in the event, and to the extent, that the negligence or failure to use Good Engineering and Operating Practice of Dawson or the other defendants caused or contributed to Dawson’s failure to perform. As AGL appears to accept, it bears the onus of proof in those respects. AGL cited Gamlen Chemical Co (Australasia) Pty Ltd v Shipping Corporation of India Ltd5, a case dealing with a claim by a shipper of goods by sea against a carrier for damages for loss of the goods, where Samuels JA (with whom Moffit P and Reynolds JA agreed) said: 6 “The correct sequence of pleading is set out in The Glendarroch in the judgment of Lord Esher MR, where his Lordship makes it plain 5 [1978] 2 NSWLR 12. 6 [1978] 2 NSWLR 12 at 23. -- 23 of 43 -- 24 that the plaintiffs must first prove the contract and the non-delivery or the delivery in a damaged condition, to which the defendant may plead an exception, leaving it then to the plaintiffs to reply “these are exceptional circumstances, viz. that the damage was brought about by the negligence of the defendants’ servants, and it seems to me that it is for the plaintiffs to make out that second exception”. And his Lordship re-emphasizes that the proper sequence of pleadings must follow the burden of proof.” The enquiry under cl 14.1.3 would extend beyond whether the relevant occurrence was preventable, to consider whether the defendants’ negligence or failure to use Good Engineering and Operating Practice has caused or contributed to (relevantly here) the under-supply of gas other than by being a cause of the occurrence. Upon the defendants’ argument, if the general words of the definition of Force Majeure Event do not apply, clearly the enquiry under cl 14.1.3 would include a consideration of whether the occurrence itself was the result of their default. Upon AGL’s argument, that matter would be considered under the general terms of the definition. [76] Under that definition, it must be noted that the relevant question is not whether Dawson’s conduct was in all the circumstances reasonable. Nor is the question simply whether Dawson acted in all respects according to Good Engineering and Operating Practice. Rather, the essential question is whether the relevant occurrence was preventable by the means which are there described. [77] Any consideration of the impact of the general words of the definition requires the relevant occurrence to be identified. The defendants’ principal argument is that the occurrence was the failure of a number of wells. In particular they say that RG 3, RG 6, RG 7, RG 10, RG 11 and RG 13 were failures which together made for a Force Majeure Event within para (h). Alternatively, the defendants say that the event was constituted by the unpredicted, sudden and material deterioration in productivity of more than one well. Either way, they argue that the nature of such events is such that they cannot be prevented or overcome: once such an event has happened it cannot be undone. In particular it could not be “overcome” by drilling other wells. That last submission is correct, but it is another matter as to whether such events of their nature are not preventable. The defendants submit that the word “prevent” simply means “stop”, so that again, that cannot be done once such an event has already occurred, and nor would it be “stopped” by drilling other wells. [78] However, in this context, the word “prevent” means, amongst other things, to avoid the relevant occurrence, to preclude it from happening. In one sense, each of these so called failures or deteriorations was preventable simply by the well not being drilled in the first place. That cannot be what the parties have agreed. But if, for example, the failures could have been avoided by a different drilling technique employed for those particular wells, then the failures of those wells were preventable in a relevant sense. [79] Alternatively, if the Force Majeure Event is characterised not so much as the failure of those specific wells, but more generally as a failure of six wells, then it would be relevant to consider whether that failure could have been prevented by drilling that number of wells in other locations. Accordingly, I would reject the defendants’ argument that the nature of the failure or deterioration in productivity of wells is -- 24 of 43 -- 25 such that it was not preventable in any relevant sense. I will consider then the facts as to whether what happened in relation to the actual wells in Ridgedale or alternatively, the same number of wells, could have been prevented. What was wrong at Ridgedale? [80] It is not suggested by either side that a problem at Ridgedale was a shortage of gas. The problem was in extracting the gas. AGL appears to accept that the problems at Ridgedale were the result of the particular geology in that area. Indeed, in relation to what is the geological state of Ridgedale, the defendants heavily rely upon evidence of Dr Levine, a geologist called by AGL. For the most part the dispute seems to have involved whether the geological conditions described in Dr Levine’s report could have been predicted or detected, and if so, whether their impact could and should have been avoided. [81] The defendants argue that each of the Ridgedale wells failed or underperformed because of certain faulting and the shearing and presence of coal fines within the coal seams at Ridgedale. They contend that these conditions were not predictable or discoverable by any kind of exploration. On that basis, they would say that the encountering of those conditions and the consequent failure or underperformance of wells was not preventable. [82] The first question then is whether the history of the Ridgedale wells was due to those factors. In particular there is a question as to whether it was faulting of a certain nature which caused these wells to fail or perform poorly. The defendants say that the critical faulting was low angle thrust faulting. As explained by Mr Rhodes, a consultant geologist called by the defendants, there are three basic types of faulting associated with the movement of the earth’s surface: normal faulting, reverse or thrust faulting and strike-slip faulting. In both normal and reverse faulting, the principal direction of the movement is vertical; in strike-slip faulting it is horizontal. Normal faulting occurs in so called extensional regimes whereas reverse or thrust faulting occurs in compressional regimes. Where there is that compression, it induces a “folding” of the rocks, inducing in coal seams what is called seam roll. As the fold becomes extreme and the fold cannot absorb the compression, a fracture occurs which becomes a fault line and as the compression continues, the fault can propagate over a longer distance. This compression causes an upward movement or “thrust” of the surface on one side of the fault line. A “low angle” reverse fault is one where the fault line is at less than 45 degrees to the horizontal. Of course the lower the angle of the fault line, the less will be the vertical displacement of the fault. [83] In the area of the Moura mine there are both major and smaller faults. Dr Levine explained that there are several major faults having a vertical displacement or “throw” which had been measured at up to 150 metres. But he described also the presence of: “many smaller faults having similar geometry, but much smaller displacement [which] are too numerous and their displacements too small, to allow them to be mapped or identified on an individual basis.”7 7 Report of Dr Levine (exhibit 8), page 68. -- 25 of 43 -- 26 He adopted a 1987 study by a Mr Hammond, noting the author’s description of “the predominance of low angle thrust faulting”, which Dr Levine says is an important aspect of the geological structure here. Dr Levine wrote that the likelihood of encountering low angle thrusts increases to the north across this zone. It would follow that this likelihood increases north from Hillview to Ridgedale. [84] Again, adopting the Hammond study, Dr Levine described the impact of faulting upon the coal seams and said that they would cause features called shear zones and slickensided surfaces which would in turn cause “borehole stability problems in CSG [coal seam gas] extraction.”8 He described the slickensided surface of coal as being a characteristic feature of both major and minor faulting. These slickensided surfaces appear within so called “shear zones”. He described the shearing as resulting in a change of shape to the coal or adjoining material which was akin to that produced by pushing parallel to the top of a deck of cards which would result in the cards sliding against one another. 9 The result is a loss of mechanical strength so that, Dr Levine said, sheared coal or sheared rock will readily separate or fall apart, a fact having “important implications for the mechanical behaviour of the rock material during CSG drilling and production”.10 [85] Dr Levine summarised the problems encountered during drilling and production at Ridgedale, adversely affecting CSG production, as being: “a. discontinuities and complex topology [shape] of the target coal seams, which made it difficult to remain within the coal while drilling horizontally; b. mechanical weakness and instability of the coal and associated strata…which prompted the collapse of well bores both during drilling and subsequent production; c. low mechanical strength and lack of physical integrity of the coal, which prompted the formation of coal fines.” The shearing of the coal and associated strata he described as “mostly related to faulting at various scales”. He wrote that slickensided surfaces are present in major fault zones, but they can also form with only slight amounts of displacement. 11 [86] He wrote that there is evidence that coal fines have had two adverse effects on CSG production here. The first is that they tend to block the “plumbing system” by which both water and the gas is drawn from the coal seam. Secondly, coal fines migrated into the production wells causing damage to water pumps, thereby hindering the “dewatering” of the coal which is a necessary step preceding the extraction of the gas. [87] These geological problems, according to Dr Levine, were caused by or related to, the influence of faults. Low angle faults had caused that mechanical instability and weakness in the coal and adjoining material, higher angle reverse faults had displaced, segmented and compartmentalised the coal seams, occasional normal 8 Exhibit 8, p 69. 9 Exhibit 8, p 31. 10 Exhibit 8, p 31. 11 Exhibit 8, p 70. -- 26 of 43 -- 27 faults had further disrupted the strata and the shear deformation of the coal and associated material was “mostly related to faulting at various scales”.12 [88] This evidence was tendered by AGL and accepted in the defendants’ case. But somewhat surprisingly, AGL ultimately submitted that there was no evidence that any problem at Ridgedale was caused by minor faults and pointed out that the defendants’ own documents referred to major faulting as being the cause of their drilling difficulties.13 I find that the relevant geological conditions which caused the difficulties at Ridgedale were those which Dr Levine described. They included minor as well as major faulting, a matter of some importance because of the limits on the extent to which minor faults are identifiable by known exploratory techniques. Could better drilling have helped? [89] The next question is whether Dawson could have drilled and operated the wells which failed, at those particular locations, in some way which would have avoided those consequences. [90] For the most part AGL argued that Dawson should have predicted or discovered the relevant conditions, and drilled elsewhere either within or outside Ridgedale. But it also criticised some aspects of the drilling and operation of these particular wells, quite apart from their location. In particular it criticised the use of what is called the “boat design” of wells and contended also that shorter laterals should have been drilled. [91] Generally coal seam gas is extracted using vertical or horizontal wells. A vertical well is drilled vertically into the surface passing through one or more coal seams. Horizontal or lateral wells have many designs, but generally they involve the drilling of a well from the surface to a coal seam and then, broadly speaking, horizontally or laterally along the coal seam. Water and then the gas is drawn from the coal seam. At Moura, Dawson has used a well design by which the water and gas is drained into the lateral well, in which it then passes to a vertical well with which the lateral has intersected. In this configuration the vertical well is called the production well. One difficulty in this type of well is to accurately drill the laterals so that they remain within the coal seam. The driller is operating from the surface and relies upon such information as to the location of the seam as is available. Quite apart from faulting, the driller must consider what is referred to as the dip or strike of the coal seam, which is the angle of the coal seam to the earth’s surface. Another problem is in ensuring that the lateral is drilled so that ultimately it intersects with the vertical or production well. [92] A so called boat design was used in many of the wells at Hillview and in turn at Ridgedale. With this design, the laterals, if viewed from above, would not follow a straight line to the vertical well but would curve towards that well as they approached it. To drill these laterals is relatively more difficult and generally speaking, the prospects of the laterals moving in and out of the coal seam and of their collapsing or of the drilling equipment getting bogged are increased. Similarly, those prospects are increased according to the length of the laterals. Ordinarily laterals have a length of at least several hundred metres. 12 Exhibit 8, pp 2-3. 13 Written submissions, paragraph 135. -- 27 of 43 -- 28 [93] Mr Cunnington is a drilling contractor called as a witness by AGL. He was critical of the amount of information which Dawson had provided to its drilling contractor. He also said that the drilling techniques and well designs used at Ridgedale were “high risk”, especially because of drilling difficulties which had been encountered with the same techniques and designs at Hillview. AGL also relies upon the fact that when Dawson moved its operations after Ridgedale to the area called Pretty Plains, it did not use the boat design and used shorter laterals. [94] It is said that Dawson had not learnt from its drilling difficulties at Hillview and effectively committed similar errors at Ridgedale. However, overall the production from Hillview was successful. This provides strong support for the defendants’ argument that there is no necessary correlation between difficulties experienced in drilling a well and its subsequent production performance. There is evidence that drilling difficulties, and in particular excessive drilling or “overdrilling”, which is sometimes caused by drilling laterals which have to be redirected because they have deviated from the coal seam, can cause damage by affecting the stability of the area in which the lateral is inserted, making it prone to collapse and affecting fines movement. There is evidence here of overdrilling to an extent which, I accept, was caused or contributed to by the drillers having insufficient information as to the location of the seam in order to say within it. AGL’s witness, Dr Holland said that there “may or may not be” a correlation between overdrilling and production. This uncertainty makes relevant here the different burdens of proof, according to whether they are the general words of the definition or the terms of cl 14.1.3 which are being applied. Overall the evidence does not demonstrate that the drilling program was causative of a subsequent failure of a well to produce either at all or satisfactorily. But nor is it proved that problems were in no case preventable by less overdrilling. [95] There was a considerable amount of evidence as to whether the drilling was conducted according to usual and reasonable practices. I mentioned Mr Cunnington’s criticism of the well designs as high risk. Dr Holland said that Dawson should have considered another technique called under-balanced drilling. But he did not go as far as supporting the pleaded case of AGL that under-balanced drilling should have been used according to Good Engineering and Operating Practice. Nor was that supported by Mr Cunnington who did not refer to the technique at all and ultimately AGL appeared to abandon this point. [96] Although Mr Cunnington was critical of the well design, Dawson had considerable advice in favour of its use at the time. A firm of consultants called Geogas in June 2006 advised that the boat design allowed for better gas drainage efficiency and that if drilling boat laterals proved difficult, an alternative pattern called the Chevron pattern might be used. In January 2004 a firm of consultant geologists, Peter R. Ellis & Associates, recommended the continued use of the boat design wells for a number of reasons. The defendants’ witness Mr Rhodes said that one advantage of the boat design is that its track allowed it to pass through the greatest volume of coal giving it the best overall recovery rate. Mr Cunnington’s criticism of the boat design did not consider the advantages in production from that design. Overall I am not persuaded that the use of the boat design or the length of laterals at Ridgedale (which was no greater than those successfully operated at Hillview) was inconsistent with Good Engineering and Operating Practice. Moreover the boat design and the length of the laterals is not shown to have affected the productivity of the wells. Further, I am satisfied that the production difficulties, and in particular -- 28 of 43 -- 29 the failure or lack of success of wells at Ridgedale, could not have been prevented simply by avoiding the boat design or by drilling shorter laterals. [97] AGL’s major criticism made of the drilling at Ridgedale is that it was made without sufficient information as to the geology. AGL says that this made for less efficient drilling and in particular much “out of seam” drilling, but that it also resulted in the wells being wrongly located relative to faulting. The “overdrilling” is then largely attributed by AGL to insufficient geological information. The essence of AGL’s case is that Dawson did not conduct sufficient exploration at Ridgedale, which is discussed below. But before going to that I should refer to another matter in relation to drilling and the arguments about the operation of the wells. [98] The first of those points is that the defendants argue that if criticism can be made of the drilling, it is not a criticism fairly levelled at any of the defendants rather than at their independent drilling contractor. For several reasons that submission is unpersuasive. The first is that it was Dawson which controlled the design of the wells. If that design did not accord with Good Engineering and Operating Practice, in my view it is no answer to say that the drilling contractor did not point that out to Dawson. Similarly, it was for Dawson to procure the necessary information as to the geological conditions to guide the drillers, and Dawson could not be said to have acted according to Good Engineering and Operating Practice simply from the fact that the drilling contractor was prepared to drill as and where Dawson directed with what information it was given. Operation of the wells [99] AGL’s case was also critical of the operation of the Ridgedale wells in several respects. One was that Dawson failed to properly collect data from the wells. In its ultimate argument, AGL did not include this within the particulars of Dawson’s departure from Good Engineering and Operating Practice. Nevertheless, its submissions were elsewhere critical of Dawson’s monitoring of wells and gathering of data. But they did not explain the connection between that shortcoming and the problems with these wells at Ridgedale, except in so far as it may be related to the matter discussed in the next paragraph. [100] AGL was also critical of what it said was Dawson’s practice of bringing new wells into production too quickly. In 2003 Dawson was advised by consultants to slow down the rate at which it was dewatering its wells and reducing the pressure ( the process by which gas leaves the coal seam). Dr Holland said that if the wells were brought on too rapidly, meaning that the pump rate was too high and the velocity of fluids moving in the well was too high, then the fluids tended to pick up debris, and in particular coal fines, to excessive levels. I accept that evidence. But the next question is whether this actually occurred at Ridgedale. [101] Mr Bryon works for Dawson as a well field team leader at Moura and has worked there since 1996. His role was and is to oversee the drilling process and operations in the field, including the dewatering and bringing into production of wells. Ultimately in cross-examination, he conceded that in hindsight the wells were “brought on too quickly”, although at the time he did not believe that to be the case.14 I accept that Mr Bryon believed at the time that the wells were not being brought on too quickly. However, Dawson received advice in 2003 from 14 Transcript day 11, p 54. -- 29 of 43 -- 30 Dr Williams of Geogas which was very critical of Dawson’s practices at Hillview in this respect. He wrote that there was clogging of pumps by coal fines resulting in sudden loss of gas production which was caused by de-pressuring the wells too quickly.15 Mr Bryon said that he had disagreed with this criticism at the time, although he did not take the matter up with Dr Williams. The likelihood is that nothing changed in response to Dr Williams’ advice. Dr Williams was not called as a witness. But importantly there is that concession by Mr Bryon that he now believes that Dawson erred in this respect and I find that in this way there was a failure to exercise Good Engineering and Operating Practice. There are then, however, questions of causation. [102] Considered in the context of whether this was a Force Majeure Event according to the general words of the definition, the question would be whether a proper rate of bringing wells on line could have prevented the failure or lack of success of the wells at Ridgedale. In this context it would be for the defendants to prove that what occurred was not preventable by this means. That would require a detailed consideration of what happened in the failure or non-performance of the wells, one by one. Not every well failed or underperformed because of problems with coal fines although, speaking generally, fines were a significant problem in the Ridgedale production. Unfortunately the respective arguments did not descend to the detail of whether a proper practice in this respect would have made a difference to a well, case by case. The defendants instead argued more broadly that there was no departure from any proper practice. In that they relied upon evidence of Mr Rhodes to that effect which, in my view, does not detract from the force of the concession made by Mr Bryon. Indeed, it is difficult to see how Mr Rhodes was able to venture that view, given the absence of records which is the subject of the inadequate data complaint. [103] Clearly RG 3 and RG 13 did not “fail” because of coal fines for there was no production. RG 7 is described by Dr Holland as failing through “bad hole conditions”, RG 10 by the collapse of the coal seam and RG 11 with “nightmare drilling and differential sticking”. Therefore a least for most of the wells which are relied upon as failures constituting the Force Majeure Event, the problem does not seem to have been coal fines. Viewed as one single Force Majeure Event, the failure of (in total) six wells16 could not have been prevented by the proper dewatering and bringing into production of the wells. So to that extent I accept that the defendants would have discharged the onus (if any) under the general terms of the definition. As for the wells said to have been the subject of a sudden deterioration in productivity, the incorrect practice of Dawson in this respect may well have substantially have contributed to the underperformance of the well. In those cases I would be unpersuaded that the defendants had proved that what happened with those wells was not preventable by the adoption of the proper practice. [104] Alternatively, there is the question under cl 14.1.3 of whether Dawsons’ failure to use the proper practice caused or contributed to some extent to what happened at the wells. What I have said in relation to the suggested failures applies here: therefore it is not demonstrated that the failure of those wells in total, viewed as one Force Majeure Event, failed for this reason. In relation to the wells relied upon 15 Exhibit 35, p 29. 16 The alleged “failures” being RG 3, RG 6, RG 7, RG 10, RG 11 and RG 13. -- 30 of 43 -- 31 under the “deterioration” heading, I would not be persuaded that AGL had discharged its burden of proving that all or part of the under supply was caused by this matter. Again that is the result of the fact that AGL’s case did not descend to an attempt to prove, well by well, the likely impact of this poor practice. [105] AGL is critical of Dawson’s response to problems with its wells and in particular of the extent to which it did or did not conduct “workovers”. A workover might involve the repair or replacement of the pump or the flushing out with water, and the blowing out with air compressors, of the wells. AGL’s argument appears to be that this contributed to the demise of wells at Ridgedale and also amounted to a failure to use Good Engineering and Operating Practice to remedy or abate the Force Majeure Event. These arguments were not supported by any opinion evidence. [106] Mr Bryon gave evidence of the process of working over wells and the defendants tendered schedules17 of the workovers conducted from April 2006 to October 2007. Further, Dawson’s records show various interruptions to production, which AGL accepts were the result of wells being turned off for workovers. Undoubtedly Dawson did have a practice of working over wells. [107] After the Curtailment Notice was given in July 2007, there are records of workovers of these wells: RG 1, RG 5, RG 6, RG 7, RG 10, RG 12 and RG 15. AGL’s point appears to be that other wells were not worked over after the Curtailment Notice, contrary it says to the requirement in cl 14.1 that it remedy the Force Majeure Event. There is an artificiality in this argument which comes from the fact that the Curtailment Notice was given so long after it was apparent that wells had failed or were relatively unsuccessful. If proper attempts had been made to remedy the problem long before the Curtailment Notice, there was no obligation from cl 14.1 to pointlessly repeat the exercise. I am satisfied from Mr Bryon’s evidence that any failure or deterioration in productivity of the Ridgedale wells could not have been prevented or overcome by further workovers. As to cl 14.1.3, I am not satisfied that there was any negligence or failure to act in accordance with Good Engineering and Operating Practice in this respect. Exploration at Ridgedale [108] I come now to the subject of exploration. AGL’s case is that Dawson failed to properly explore the Ridgedale field, with the result that it drilled wells in the wrong places at Ridgedale or failed to simply avoid Ridgedale and go to other areas within the mining lease, such as Pretty Plains where it went after Ridgedale. The defendants’ case is that the exploration was appropriate but that the geological problems at Ridgedale were not discernible by any exploration technique. [109] Ridgedale is an area immediately to the north of Hillview. On the surface the two parcels were distinguished simply by a fence rather than by any obvious difference in the landscape. The area covered by the Hillview wells was about 5.5 square kilometres and that covered by the Ridgedale wells was about 3 square kilometres. By the time the first production well at Ridgedale was drilled, Hillview had enjoyed successful wells for some years. There had been drilling difficulties and other problems, and in particular problems with coal fines. But for the most part, they had been overcome and the history of the Hillview production is quite unlike that of 17 Exhibits 120 and 173. -- 31 of 43 -- 32 Ridgedale. As at the end of 2005, the actual production at Hillview substantially accorded with what had been forecast. [110] In these circumstances Dawson appears to have been confident in the drilling of Ridgedale, in following practices and well designs which it had employed at Hillview. It did undertake some exploration, but its approach was, as described by Mr Rhodes, a “stepping out” into Ridgedale. This describes an approach in which Ridgedale would be developed incrementally from its southern boundary adjoining Hillview, at first one “step” or well space from the most northern of the Hillview wells. In effect the approach was to ignore the property boundary and to drill as if Ridgedale was part of Hillview. Ridgedale was considered, at least by Mr Stay, to be a “brownfield”, as distinct from a “greenfield” area which is one which is completely unknown. Hence Mr Stay rejected the suggestion that there was a need for a pilot production program for the Ridgedale wells because, in effect, the pilot had been the Hillview wells. [111] AGL’s argument that it was necessary for Dawson to conduct a pilot production program specifically at Ridgedale is unpersuasive. AGL’s witness Dr Holland agreed that it was not necessary. He suggested that some production testing was something which could have been considered by Dawson, but he also accepted that a program of stepping out from an existing production well could be undertaken without either a pilot production program or other production testing. [112] AGL’s argument is critical of Dawson for going into Ridgedale at all. However, no more was known of any alternative area, such as Pretty Plains, than was known of Ridgedale prior to any drilling being conducted there. It was necessary for Dawson to go somewhere and to conduct whatever was the appropriate exploration. So a move to Ridgedale of itself cannot be fairly criticised. The question is whether Dawson should have conducted further exploration before it drilled its production wells and whether it could have and should have moved to another field when the problems at Ridgedale became or should have become apparent. [113] In January 2004 Dawson had a written advice from an external consultant geologist, Mr Ellis. He provided a further advice in March 2004. He said that in “late FY04 or early FY05”, it would be necessary to develop some area beyond Hillview and he referred to four areas which had been identified. [114] Ridgedale was one of them. He referred to it as the Luhrs area, that being the name of its then owners. Although the area was within that of the mining lease, it was necessary for the defendants to purchase the freehold or negotiate rights of access in order to undertake exploration and production drilling. It was also necessary to obtain a cultural heritage clearance over any land which would be the subject of that work. The defendants say that this requirement in particular was an impediment to their progress at Ridgedale and to further exploration work. [115] Another area was described by Mr Ellis as QNP, which was also known as Queensland Nitrates or Plainview. This was land adjoining Ridgedale on its north-east boundary. It was subject to the mining lease but there were also surface rights already held by Anglo Coal. A third area was freehold described as WTH, because it was owned by people called Williamson, Tarry and Hetherington. The fourth area was called Tremere or as it is more commonly called now, Pretty Plains. This is immediately to the south of Hillview. Mr Ellis wrote that Pretty Plains had -- 32 of 43 -- 33 not been considered further at that stage because of “perceived access and production difficulties due to the area being held as leasehold” and because its potential gas content was thought to be lower than in the other areas. [116] Importantly Mr Ellis cautioned that none of these areas had any reliable drill hole data or gas content data and should “essentially be considered as green to brownfield status”, meaning that there was little to nothing known of the geology. [117] Mr Ellis recommended that the next area to be developed after Hillview should be QNP. His reasons were that the defendants already held surface rights and that some of the exploration and extraction would complement work which was to be done in that area for coal mining. He said that it would then be necessary to develop the Ridgedale area “in late FY06 to FY08”, depending upon the number of production wells to be drilled. In that respect he referred to two proposals, one of Mr Regan for a total of 112 lateral production wells in the years FY04 through FY08, and one by a Mr Robertson for a total of 84 production wells within the same period. He warned of the geological risks that might affect the reliability of either of those estimates, but these risks were common to the QNP, Luhrs and WTH areas. They were: “• more intense faulting than currently interpreted • change in location of major faults to reduce the available area for lateral well development • igneous intrusion of seams • less gas than currently interpreted • changes in dip direction • changes in cleat and fracture direction”. [118] Then in his March 2004 document, he wrote that in Ridgedale it would be necessary to create a reliable geological model, and in particular to determine seam dip and dip direction, cleat and fracture directions and to assess fracture and fault intensity. He recommended the drilling of 12 rotary chip holes and 10 diamond core holes as part of that exploration work. That advice was not followed. [119] As it happened, the next area which was explored was not QNP but Ridgedale. That decision had been made by September 2004 although the evidence does not show precisely when. In October 2004 negotiations for the acquisition of Ridgedale were commenced and exploratory drilling commenced that December. An access agreement with Mr Luhrs for drilling on Ridgedale was signed in January 2005 and in March 2005 the second and third defendants contracted to purchase the freehold. [120] Work was done from time to time during 2005 towards obtaining cultural heritage clearances for various parts of Ridgedale. The extent to which this work was performed expeditiously or otherwise was explored with several witnesses but it is not so clear that Dawson is guilty of some significant delay once it began that work. A different question is whether that work, and similarly the acquisition of the freehold of Ridgedale and the prior grant of rights of access to it, at least for exploration work, should have been undertaken much earlier. Mr Ellis wrote in January 2004 that: “negotiation with the stakeholders in the four potential seam gas production areas requires to be commenced very soon so that exploration and development activities can commence”. -- 33 of 43 -- 34 There is no explanation as to why negotiations with Mr Luhrs did not commence until October 2004. Whether it was to be QNP or Ridgedale which was drilled after Hillview, at some stage the defendants had to acquire Ridgedale, or sufficient rights over it, and undertake cultural heritage clearance work there. [121] Dawson expected to encounter much the same faulting at Ridgedale as it had encountered at Hillview. Dr Holland said that in May 2005 it would have appeared that the amount of faulting in the Ridgedale area was similar to that in Hillview, perhaps increasing in severity.18 Mr Stay had seen the results of seismic surveys conducted along the southern and eastern boundaries of Ridgedale, one showing “very little faulting” and the other (on the eastern boundary) identifying a fault in the north-eastern corner of Ridgedale. This did not indicate to Dawson that Ridgedale would be significantly different. I accept that is so but this would not have provided an excuse for not undertaking a proper exploration of Ridgedale, especially having regard to the advice of Mr Ellis. [122] Dr Holland gave evidence that in May 2005 it was possible to predict a disturbance of coal within the seams by low angle thrust faults on the basis of those seismic surveys the results of which Mr Stay had seen. But if that is not correct, nevertheless, there was a need for due exploration. [123] The same applies to the defendants’ argument that independent geological studies then available, and in particular studies by the CSIRO, showed relatively little faulting. Mr Rhodes said that these reports indicated nothing unusual in the Ridgedale area which would lead to a prediction of the drilling and production problems that were encountered by Dawson. 19 These are matters which justified, contrary to AGL’s criticism, Dawson’s move to Ridgedale in the first place: it was not so obviously risky that it should have been avoided without exploration. But it cannot be thought that this obviated the necessity for exploration. [124] I turn then to what was done by Dawson at Ridgedale. The relevant exploration undertaken by Dawson was as follows. Four slimcore holes were drilled by a contractor called Phoenix Drilling, the first of them on 15 December 2004 and the last on 3 March 2005. Four chip-air holes were drilled by Phoenix within the same period. Eighteen holes, numbered LH 1 to LH 18, were progressively drilled ahead of production drilling as it advanced into Ridgedale. There was some seismic exploration: as already mentioned, seismic lines had been shot along the southern and eastern boundaries at Ridgeale. Another seismic line was shot into Ridgedale in early 2006 in relation to seismic surveys being conducted in Plainview. Dawson also relies upon four seismic lines which were shot in Hillview in late 2004 but as to these, they did not represent the exploration of any part of Ridgedale but instead they seemed to be relevant to Dawson’s case that the geology of Hillview was a good guide to that of this area. [125] Dawson also relies upon its experience in drilling production wells in Ridgedale as being useful exploration. Its case is that this progressive or incremental approach to exploration was adopted because of issues concerned with cultural heritage clearances which are discussed below. 18 Transcript day 8, p 34. 19 Exhibit 37 at [53]. -- 34 of 43 -- 35 [126] The normal spacing between wells was about 400 metres, this involving one “step” in the process. As it happened in Ridgedale, Dawson took more than one step at a time. RG 1 was within one such step from Hillview as was RG 12 which was drilled much later. But RG 5, the next well into production (December 2005) followed by RG 2 (January 2006) were outside that 400 metres, as Mr Stay agreed.20 And in stepping further into Ridgedale, Dawson could not have relied upon the unproven performance of the production wells at Ridgedale. Further, the drilling of RG 1 had been problematical. Its northern lateral had to be re-drilled after faulting was encountered. [127] Dawson nevertheless defends its incremental approach and seeks support for that in evidence from Dr Levine. In re-examination he was asked whether “it is appropriate to extend the results of your established proven producing wells by two well spacings?”, to which he answered that: “one could make that sort of extrapolation but there is a lower level of certainty, or a higher level of risk associated with increasing distance away from established proved producing production.” He said the safest means of proceeding would have been to have drilled a well one spacing away from an established proven producing well and waited “a few months” to see if that became a proven producing well. Clearly that was not done at Ridgedale. Having regard to the expected decline in production from Hillview, Dawson did not have the time to proceed in that way if it was to have any chance of having sufficient new wells to meet the MDQ. [128] Dr Levine said that the principal goal of the Phoenix drilling program was to estimate the gas content of the coal. The core holes were to obtain core samples to that end and the chip-air holes were drilled prior to the core holes to provide an indication of the depth and thickness of the coal seams for the core drilling. Dr Levine noted that only one of these core holes was able to be completely logged and that the logs for two of the holes indicated extensive bore hole “break outs” or “caving”, which he said was consistent with the drillers’ reports for these wells which indicated “the severity of the caving problems which prohibited them from completing the drilling of these wells and in all but [one] case prevented their being logged.” I accept Dr Levine’s conclusion that the likely explanation for the drilling problems in these wells was shearing of the coal related to structural deformation. Dr Levine said that he would have been concerned about the drilling problems encountered by Phoenix and would have proposed “follow up work to try to better understand the source of these problems prior to the commencement of production drilling”.21 He reached that view also by reference to certain exploration conducted by BHP in 1994-95. [129] The defendants seek some support from evidence of Dr Holland where he conceded in cross-examination that a practice of progressively gathering information was not an indication of poor operating practice. But this evidence says nothing about the number of bore holes which should have been drilled for exploratory purposes. The defendants also suggest that there is conflict between the evidence of Dr Levine and their witness Mr Rhodes as to the need for further bore holes. That conflict is 20 Transcript day 15, p 19. 21 Exhibit 8, p 106. -- 35 of 43 -- 36 difficult to discern. In his second report,22 Mr Rhodes was asked to respond to the question: “Did the defendants drill and analyse sufficient bore holes at Ridgedale prior to the commencement of drilling?” His purported response was: “The move into Ridgedale was seen as stepping out from Hillview into an area considered to be a proved undeveloped area i.e. a brownfield expansion. I would not consider the decision to move in that direction to be any different today to when it was originally made.” This hardly contradicted Dr Levine’s evidence on the point. [130] As Mr Stay agreed, the LH holes were placed in order to identify the immediate location of the coal seam to assist in the drilling of wells. He agreed that the purpose of the LH holes was not to “identify unstructured ground”.23 [131] AGL contends that Dawson should have used seismic surveys to explore or further explore Ridgedale. That the seismic technique was appropriate does not appear to be in dispute. The defendants tendered evidence from Mr Rhodes that he would have carried out more seismic exploration had there been no access or cultural heritage issues.24 And importantly, when asked whether there were “any particular reasons why seismic surveys were not undertaken?”, Mr Stay said: “We didn’t have clear clearance (sic) to the block to run seismic lines”. When cross-examined he said that he agreed with what was written in an internal memorandum of September 200525 of the utility of seismic exploration and in particular statements there that: “A number of seismic lines will give a good indication of seam structure (dips and major faults) and is considered the best method of an assessment of the potential of the area and for target generation of further exploration drilling. This is aimed at defining potential areas of additional reserves… The seismic survey will provide the necessary information on seam structure to allow better mine planning, more efficient exploration drilling (especially for Seamgas M R Drilling) and seamgas extraction planning.” [132] Seimsic has been used as part of Dawson’s exploration program more recently conducted at Pretty Plains. In the AGL case, Dr Holland, Dr Levine and Dr Applegate each thought that further seismic exploration should have been undertaken. There seems to be no real dispute and I find that further seismic exploration was a widely known and proven technology which was generally available and consistent with Good Engineering and Operating Practice at the time. [133] The defendants’ answer to the case for seismic exploration is that it was not possible, because of limitations of access to Ridgedale, and in particular because of 22 Exhibit 90. 23 Transcript day 14, p 30. 24 Exhibit 37, pp 93-94. 25 Exhibit 180.3. -- 36 of 43 -- 37 the fact that not all of Ridgedale had received a cultural heritage clearance. This was because a clearance of all of Ridgedale would have taken too much time and postponed the production from Ridgedale which was necessary, given the natural deterioration at Hillview and the unavailability of other gas from the field, to meet Dawson’s commitments under the Agreement. Further, the defendants strongly dispute that more seismic exploration would have been useful, because the geological conditions which they say were the cause of the problems for the Ridgedale wells were not detectable by this means. [134] Before going to those arguments, it must be noted that there was considerable support for AGL’s case within the defendants’ contemporaneous documents, in that they record acknowledgments of the inadequacy of the exploration at Ridgedale. In their “Business Plan and Budget Book 2006”, these things appear: “Drainage started in the Hillview field with excellent results. Good drilling conditions were experienced and 37 wells were drilled… Operations then moved to the Ridgedale field in 2006 with disappointing results to date. High gas contents are known to be present in the coal however very difficult drilling conditions were experienced due to major faulting, despite the close proximity to the less disturbed Hillview field… The business is currently suffering from declining profits…due to: • Insufficient geological data in what has turned out to be a complex geological environment resulting in the escalating capital cost of new wells and poor production performance…” In another internal document, dated 13 April 2007, 26 it was recorded that: “The main cause of the disappointing results in the Ridgedale field…was the lack of Geological data. The Ridgedale field was immediately adjacent to the very successful Hillview field and it was expected that similar conditions would be experienced. Despite this, very difficult conditions were experienced. To minimise the risk of this happening again in Pretty Plains, an exploration program was completed over the area. This program has shown very promising results.” Mr Stay said in evidence that this accorded with his assessment at the time. [135] From a meeting of 23 April 2007, recorded as a “Dawson joint venture technical meeting”, there are the following notes as to the “lessons learnt from Ridgedale”: “Insufficient exploration – incorrect assumption of similar geology with attractive higher gas contents. Adverse seam structure – large scale faulting – drilling difficulties and extra costs – prevented completion of some wells (e.g. Ridgedale 3 and 13). Impacts on gas migration (e.g. wells still not producing to 26 Exhibit 19. -- 37 of 43 -- 38 forecast levels); increased “out of seam” drilling; and unstable ground around faults more prone to collapse.” Mr Stay also said that he agreed with these statements. [136] In a document headed “Gas Business Options 2008-1010 Briefing Paper”, apparently prepared in July 2007, it was written: “In 2006 and 2007 production has been below plan as a result of poor production from a northern development field known as Ridgedale caused by unexpectedly difficult geology. In mid-2006 a decision was made to expand to the south to Pretty Plains and incorporate learnings from the failed Ridgedale program such as the use of 2D seismic and additional lateral guidance holes. During 2004 and 2005 production on the mining lease increased mostly to plan reaching about 16 TJ/day in late 2005 with a new drilling program to the north in the Ridgedale area in early 2006 forecast to increase production to the full 18 TJ/day. Almost immediately drilling problems were encountered which persevered during 2006 and all 15 wells in that area have failed to perform to plan. It was acknowledged the area had proven to be unexpectedly complex but that insufficient exploration had failed to detect this. In late 2006 a decision was made to move activities to the south in Pretty Plains but to explore more fully using drilling and seismic techniques before production drilling.” Mr Stay conceded that in July 2007 he agreed with this assessment that insufficient exploration had failed to detect the geological complexity. [137] And in discussions with Ms Deane, Mr Stay acknowledged that Dawson should have used more seismic lines at Ridgedale and that had it done so, it would not have drilled some of the wells which it did.27 [138] Dr Levine says that the combination of more bore holes and seismic would have provided the best means of obtaining sufficient or reliable geological data and that there was an insufficient number of bore holes drilled at Ridgedale to do that. Dr Applegate said that the seismic data can help determine the type of well to drill as well as assisting in the location and design of the well bore path. He said that drilling of bore holes would provide excellent information on a small area whereas seismic gave information over a much larger area. This is consistent with the view of Dr Levine that the best means of exploration would have been a combination of bore holes and seismic. [139] In my conclusion the exploration of Ridgedale was inadequate and did not accord with Good Engineering and Operating Practice. At least absent the drilling of further bore holes, Dawson should have undertaken the seismic exploration which has since been undertaken at Pretty Plains. Dawson relies on the fact that Mr Ellis had not recommended seismic exploration, and says that different views about its utility could be reasonably held. But Mr Ellis recommended more extensive bore hole exploration, which Dawson did not undertake. Further, under the general words of the definition, the question is not whether the use of Good Engineering and Operating Practice must have involved more seismic exploration. It is whether 27 Transcript day 3, p 18 as recorded by her notes, exhibit 54. -- 38 of 43 -- 39 the Force Majeure Event was preventable by some means that involved the application of that practice and of proven and available technology. Seismic exploration was within that description, and it would be for the defendants to prove that it would not have made a difference. There is no real suggestion that this seismic exploration would have involved the expenditure of unreasonable sums of money.28 As I have said, the only explanation offered for not using it is that Dawson did not have access to all of the necessary parts of Ridgedale, an issue to which I now turn. [140] In September 2003 a number of companies in the Anglo Coal Group entered into a Cultural Heritage Investigation and Management Agreement with the Palmtree Wutaru Aboriginal Corporation for Land and Culture and Toby Gangulu Dawson and Callide Valley Native Title and Cultural Heritage Custodians Inc. The agreement covered the Callide, Moura and Theodore mines. It established a protocol and procedures for obtaining land clearance for exploration and mining activities. It is under that agreement that areas were able to be cleared at, amongst other places, Ridgedale. The defendants say that obtaining cultural heritage clearance was a slow process and a backlog had developed given the number of coal mining areas which were the subject of this agreement. They suggest that at the start of the process there was a shortage of archaeologists and traditional owners available to undertake cultural surveys. There is also evidence that the traditional owners were not inclined to permit clearances of entire paddocks as distinct from individual parts which could be shown to be immediately required. All of that may be accepted, but it is not said that it was impossible to obtain at some time the necessary clearances to enable Ridgedale to be properly explored. In other words the problem, if any, was one of timing. [141] I am conscious of the advantage of hindsight in assessing all of this. However, a few matters must be kept in mind. The first is that at all times Dawson knew that it needed not only to come to terms with Mr Luhrs but also to obtain cultural heritage clearances. It knew that the Hillview field would not be sufficient to provide gas over the life of the Agreement. It had advice from Mr Ellis in January 2004 that negotiations to obtain the necessary access should be undertaken “very soon”. That did not happen and the explanation, as clearly enough appears, is that Dawson assumed that the conditions at Ridgedale would be much the same as at Hillview and was not approaching the matter of access and cultural heritage clearances with the expedition which was required. Dawson’s approach to the timing of the expansion into Ridgedale made no allowance for the contingency that its production there would be unsuccessful. As discussed, Dawson may have had no strong indications of these conditions at Ridgedale, but it knew or should have known that the area would have to be explored. Secondly, in so far as there were issues involving the scarcity of archaeologists or traditional owners available to undertake the surveys, it is far from demonstrated that the defendants’ other commitments in the employment of these resources demanded that they not be employed at Ridgedale. Nor is it said that in the process of obtaining such clearances which were obtained at Ridgedale, there were complications which substantially delayed that process. 28 Apart from the cross-examination of Dr Applegate attempting at one point to explore the cost of surveying, by a method called undershooting, an American airport: D4, p 24. -- 39 of 43 -- 40 [142] Overall this argument provides an explanation but no excuse for the inadequate exploration. It amounts to the defendants saying that by the time they chose to undertake any exploration at Ridgedale, they had insufficient time to perform an appropriate level of exploration because of the requirement for immediate production from Ridgedale to meet its commitments according to the Agreement. It provides no excuse for its non-performance for Dawson to say, in effect, that it left itself insufficient time to be in a position to perform. [143] The next question is whether proper exploration would have made a difference. [144] Neither seismic surveys nor more core holes can now be said with certainty to be something which would have revealed sufficient faulting to have dissuaded Dawson from drilling wells where it did. There are limitations on the extent to which seismic exploration would reveal low angle thrust faults of a small displacement. The defendants refer to a CSIRO report of 2006,29 where it was written that for seismic data to be reliable in the identification of faults, the fault needs to have a vertical throw of more than five metres. They also refer to a report by the contractor who undertook the seismic work at Hillview, which noted that it was not possible to predict confidently structures with vertical displacements of less than three metres. The authors of these reports did not give evidence. But Dr Applegate said that some low angle faults may involve small vertical displacements of less than three metres and that seismic data could resolve faulting in the range of 1.5 to 3 metres depending upon the depth of the coal. He described the particular surveys which could achieve that result and I accept that evidence. But it shows that not all faults, and not all of those which have been significant here, would have been detected. This is consistent with the opinion of Dr Levine that in this area there are many small faults which are too numerous and their displacements too small to allow them to be mapped or identified on an individual basis.30 [145] In all of this, the difficulty is that because the appropriate exploration has not been undertaken, it is not known what that exploration would have revealed. Of course, from Dawson’s experience at Ridgedale, it can be seen that it would have been preferable to have moved directly to Pretty Plains. But the present question is what is likely to have been revealed by a proper exploration. I accept that more information would have been revealed by seismic exploration and that to some extent, the incidence of low angle reverse faulting would have been detected. But whether this would have revealed sufficient information to have warranted the abandonment of Ridgedale remains a matter of speculation. Dr Applegate conceded that some low angle faults may have vertical displacements of less than three metres and that seismic exploration may not disclose shearing within the coal seams. There would have been also the prospect of differing professional interpretations of the results from this exploration. When re-examined, he went no further than saying that seismic exploration “may” result in the detection of relevant faulting. [146] The defendants argue that the relevant geology is now known and recorded within their so called geological model. This includes data which results from the drilling of the exploration holes and vertical production wells at Ridgedale. The defendants point to a concession by Dr Levine that had Dawson drilled further exploration bore holes prior to commencing production drilling, it would not have drilled more bore 29 Exhibit 42. 30 Exhibit 8, p 68. -- 40 of 43 -- 41 holes within Ridgedale than the exploration holes and vertical production wells which were drilled. (Dr Levine said subsequently that whether the number of holes was adequate, he considered that a reliable log data supplemented with seismic exploration was needed.) The evidence of the defendants’ Mr Johansson and of Mr Rhodes is that the current model does not identify conditions materially different from those at Hillview. Indeed Mr Johansson, now the senior geologist employed by Dawson but subsequent to the experience at Ridgedale, testified that there was nothing in this current database which would indicate that production wells should not be drilled in Ridgedale, if that decision were to be made today. [147] AGL’s case strongly challenged the completeness of the database constituting this so called model. It is unnecessary to discuss the many respects in which AGL made that criticism. The essential point is that the database is the result of only such information as has been obtained and included within it, and the interpretations of it by those who were involved in its compilation. Critically it lacks whatever would have been the information which would have been provided by seismic exploration. That exploration may have provided more information that is within this database, which may have been critical as to the location of wells within or Ridgedale or to a decision to move to another area. And in any case, for Dawson to argue that this model would not deter it from drilling as and where it did at Ridgedale, given its case of the “severe structuring and faulting” which was encountered there, strongly indicates the inadequacy of that modelling. The same point applies to the defendants’ reliance upon the content of CSIRO reports. In particular the CSIRO report written by Dr Sliwa31 was not written with the benefit of seismic information in relation to Ridgedale. [148] This uncertainty as to what proper exploration, and in particular seismic, would have revealed must then be considered in terms of the Agreement. As to the general words in the definition of Force Majeure Event, I have found that seismic exploration involved the application of proven technology widely known to and generally available for use by persons in the gas industry and that it involved the expenditure of no more than reasonable sums. If these general words of the definition apply, the onus would be upon the defendants to prove that by the use of seismic exploration nevertheless Dawson would have been unable to prevent the relevant occurrence. In effect the defendants must prove that seismic exploration would not have revealed sufficient information to make the drilling of these wells so risky that it would not have occurred. Because the extent of the problems which would have been revealed remains a matter of speculation, it cannot be said that more probably than not, the seismic exploration would not have made a difference to what Dawson did or ought to have done at Ridgedale. [149] On the other hand, considered by reference to cl 14.1.3, this uncertainty creates the same difficulty for AGL in discharging its burden of proof. In that context AGL would have to prove that to some extent, Dawson’s negligence or failure to use Good Engineering and Operating Practice in this respect caused or contributed to its failure to perform. If the information which would have been revealed would not have been sufficient to have required Dawson to drill its production wells elsewhere where the geology was substantially more favourable, then AGL could not prove that to any extent this failure by Dawson was consequential. On this point I should note that I was unpersuaded by AGL’s case that Dawson should have drilled its 31 Exhibit 42l -- 41 of 43 -- 42 production wells in Ridgedale at different locations but within that field, so as to avoid faults. Having regard to the high incidence of faulting, particularly as described by Dr Levine, I do not accept that a likely outcome of a proper exploration program would have been a reasonable level of confidence in drilling production wells at other locations within Ridgedale. There is Mr Stay’s concession that with proper exploration, some of the wells would not have been drilled but that does not identify which wells they were, and nor has AGL’s case indicated where within Ridgedale Dawson could have been successful. Rather the likely alternative course would have been to move to another field and in particular to Pretty Plains. [150] As to whether exploration would have made a diference, the defendants referred to the timing of their acquisition of Pretty Plains and the cultural heritage clearances undertaken in that field. Negotiations with its owner commenced in the first quarter of 2006 although an offer to purchase was not made until August 2006. Cultural clearance work was undertaken in late November of that year and exploration drilling began in December 2006. Further cultural clearance work, required for production drilling continued in early 2007. A contract for the sale of Pretty Plains to the second and third defendants was signed in April 2007 when the first vertical production wells were completed and drilling of lateral wells commenced in June 2007. By the end of that year six wells had been completed at Pretty Plains with another five verticals yet to have the laterals drilled. The production from Pretty Plains has been successful. But again, there is no explanation for why the negotiations and cultural clearance work for Pretty Plains did not commence earlier, as had been recommended by Mr Ellis in January 2004, apart from the fact Dawson was too optimistic about Ridgedale from its experience at Hillview to think that it needed some alternative. [151] I was also unpersuaded by AGL’s argument that an insufficient number of production wells were drilled at Ridgedale. AGL advanced a case, with some evidentiary substance, to the effect that Dawson had drilled fewer production wells overall in the relevant years than it had been advised to drill. Again, this is probably explained by undue optimism about Ridgedale. However, having regard to the production from the 15 wells which were drilled in Ridgedale, an increase in their number by, say, a third, would have made little difference to Dawson’s ability to supply the agreed quantity of gas. [152] I shall endeavour to summarise what would have been the effect of these findings, (had I not concluded that there was no Force Majeure Event for reasons unconnected with Dawson’s own defective operation): • If there was an event which was within the specific inclusion in para (h) of the definition, and if on the proper construction of that definition its general words were not then relevant, then notwithstanding Dawson’s defaults in the exploration and operation of Ridgedale, the defendants would have proved a Force Majeure Event. • If the case was within para (h), but the occurrence had to be also within the general words of the definition, then the defendants would have failed to prove that the occurrence was a Force Majeure Event. • If the occurrence was not within para (h), then because the defendants would have failed to prove that the requirements of the general words -- 42 of 43 -- 43 of the definition were satisfied, they would have failed to prove a Force Majeure Event. • If there was a Force Majeure Event, then AGL would not have discharged the burden under cl 14.1.3 to prove that to some extent, the defendants are precluded from relying upon it. Conclusions and orders [153] AGL claims declaratory relief to the effect that Dawson is not entitled to the benefit of the force majeure provisions. There will be declarations substantially in the terms which it has sought. It will be declared that: (a) the matters set out in the letter from the first defendant to the plaintiff dated 9 July 2007 do not constitute a Force Majeure Event as defined under the Gas Sales Agreement between the parties and do not entitle the first defendant to curtail the supply of gas (in whole or in part) under clause 14 of that Agreement; (b) the MDQ within the schedule to that Agreement of 18,000 gigajoules per day has not been amended by that letter of 9 July 2007, by the notice purportedly issued by the first defendant to the plaintiff on 10 December 2007 or otherwise. [154] It follows that AGL is entitled to the so called Remedy Amounts for Dawson’s under supplies from the date of the Curtailment Notice. I do not have the up to date figures to permit me to quantify that amount within these reasons. It appears that AGL has been withholding the relevant amounts, the calculation of which would not be controversial. If that is so, then AGL would not also be entitled to a judgment for the same sums. In case that assumption is incorrect, I will stand over for further consideration the balance of the relief claimed by AGL. [155] The defendants have counterclaimed for payment of the amounts withheld and interest. It follows that their counterclaim will be dismissed. [156] I will hear the parties as to costs. -- 43 of 43 --