Haylock v Patek HC Auckland Civ-1999-404-000899
[2008] NZHC 1352
•1 September 2008
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IN THE HIGH COURT OF NEW ZEALAND
CIV 1999 404 000899
UNDER the Securities Act 1988
BETWEEN ROSEMARY PHYLLIS FILLBRIDGE HAYLOCK
First Plaintiff
ANDS H CAIRNS Second Plaintiff
ANDHUGH GREEN PROPERTIES LIMITED Third Plaintiff
ANDJ W PATEK First Defendant
ANDSHELL EXPLORATION NEW ZEALAND LIMITED
Second Defendant
Hearing: 5-9, 12-16, 19-23, 26-30 May and 3-6, 9-12, 16 and 17 June 2008
Counsel: Gary J Judd QC with Patricia A B Mills for Plaintiffs
James A Farmer QC with Sarah Katz and Anna Harris for Defendants
Judgment: 1 September 2008 at 4:00pm
RESERVED JUDGMENT OF WILLIAMS J
This judgment was delivered by
Hon. Justice Williams on
1 September 2008 at 4:00pm
Pursuant to R 540(4) of the High Court Rules
…………………………………. Registrar/Deputy Registrar Date:……………………..
HAYLOCK AND ORS V J W PATEK AND ANOR HC CIV 1999 404 000899 1 September 2008
A. All the plaintiffs’ claims against both defendants fail and are dismissed.
B.Leave is reserved generally to apply in relation to any consequential issues including costs or material factual detail.
I N D E X
Paragraph
Introduction [1] (1) The Takeover of Southern Petroleum in Outline [1] (2) The 2 November 1995 Presentation in Outline [13]
Parties [18] Statute [23] Pleadings [30] A Little Geology [40] Prior to July 1995 [51]
27 July 1995 to 2 November 1995 [66]
2 November 1995 Presentation in Detail [84]
Mangahewa 2: Events After 2 November Presentation [108] (1) General [108] (2) Methanex 1: 13 November 1995 [109] (3) QPR: 15 November 1995 [117] (4) Onshore Review: 12 December 1995 [121] (5) Methanex 2: 11 December 1995 [126] (6) Presentation to Mr Patek: 31 January 1996 [138] (7) 31 January 1996 – 23 September 1996 [143] (8) 23 September 1996: Mangahewa 2 is Approved [153] (9) Mangahewa 2 [155
The Takeover in Detail [156] (1) To 16 August 29 2008 [156] (2) 16 August 1995-3 November 1995 [176] (3) 3-6 November 1995: Meetings, Reports, and Memoranda [194] (4) 8 November 1995: Messrs Patek and Oakley Meet [206] (5) 9 November 1995: Dr Haskell and Mr McCagherty Meet [212] (6) 16 November 1995: Papalia 2, Warburg 2, Southern’s AGM [220]
Authorities [224] Discussion and Decision [244] (1) Claims Against Shell [244]
(a) The Allegations in Outline [244]
(b) Was Petrocorp a Substantial Security-Holder
in Southern At the Relevant Time? [247]
(c) Did Petrocorp Have the Mangahewa Information [248]
or Inside Information About Southern “by reason of”
its Position as a Substantial Security-Holder in Southern? (d) Did Petrocorp Receive Mangahewa and Inside
Information About Southern Under s 3(1)(c)?
[261]
(e) “In Confidence” [264] (f) Dual Capacities [265] (g) Public Availability and Price Sensitivity [267] (h) Result Re Claims Against Shell [268]
(2) Claims against Mr Patek [269] (a) The Allegations in Outline [269 (b) Did Mr Patek Receive the Mangahewa and Inside
Information “by reason of” his Southern Directorship? [272] (c) Was the Mangahewa or Inside Information Available Publicly? [284] (d) Did Mr Patek Receive the Mangahewa or
Inside Information? [294] (e) Result of Claims Against Mr Patek [326] (f) Other Issues [327]
Further Discussion and Decision:
Would the Inside Information have been likely to affect materially
the price of Southern’s shares if publicly available? [328]
(1) General [328] (2) Technical and Expert Evidence [330] (a) General [330]
(b) Geological and Oil and Gas Expertise and Valuations [331] Dr Haskell [332] Mr O’Connor [340] Mr Swindon [352] Mr Tearpock [365]
(c) Share Price Analysis [413] Mr Wallace [413] Mr Stone [420]
(d) Sharebroking Evidence [434] Mr Cimino [434] Mr Benjamin [437]
(e) Further Discussion and Decision [440]
Result [475]
ANNEXURES ANNEXURE 1: Definitions of “Reserves”
ANNEXURE 2; Definitions of Other Technical Terms
ANNEXURE 3: Some Abbreviated Biographies
ANNEXURE 4: Maps: Taranaki Oil and Gas Fields (attached) Site of Taranaki Fields
Scale map
Introduction
(1) The Takeover of Southern Petroleum in Outline
[1] By mid-1995 1 the Fletcher Challenge Group owned approximately 85% 2 of the authorised capital of 175m shares divided into 350m shares of 50 cents each in Southern Petroleum No Liability (“Southern”).
[2] Southern had been an oil and gas exploration and prospecting (“E & P”) company since 1983 and was listed on the New Zealand Stock Exchange (“NZX”). On 31 July it advised NZX it had that day received an offer from Fletcher Challenge through an indirectly wholly-owned subsidiary incorporated for the purpose, Petroleum Industries Limited (“PIL”), for all the approximately 35.1m shares in Southern not then owned by another indirectly wholly-owned subsidiary of Fletcher Challenge, Petrocorp Exploration Ltd (“Petrocorp”). The offer was 63 cents for each share paid to 45 cents – the shares traded on NZX - 19 cents for each ordinary share paid to one cent and 68 cents for each ordinary share paid to 50 cents. The notice advised the offer would be submitted to shareholders on 15 August and would remain open until 15 September.
[3] The formal takeover offer was made on 15 August. The offer was conditional on acceptance by shareholders of at least 90% - said to be 206,382,291 - of the shares on issue.
1 All dates in this judgment are in 1995 unless otherwise specified.
2 Evidence as to the exact percentage owned by the Fletcher Challenge Group varied slightly; an
11 July 1995 background paper on Fletcher Challenge’s proposed takeover of Southern said Fletcher Challenge owned 84.69% of Southern at that stage. Southern’s defence said Petrocorp owned 84.82% of Southern on 30 June 1995, whereas Fisher J recorded the percentage as 84.89% in Haylock v Southern Petroleum NL [2002] 3 NZLR 518, 523 para [10]. The takeover offer for Southern said Fletcher Challenge held 84.7% of its shares prior to 31 July 1995, bought out National Mutual, the largest minority shareholding, of 2.8% on that day, and held 87.5% of the shares in Southern on
15 August 1995.
[4] In the absence of two of their number, Messrs Patek and Taylor of Petrocorp, the Southern Board appointed two independent directors, Messrs Geary and Cameron, as a committee to evaluate the offer on behalf of minority shareholders. Those directors commissioned reports on the offer from Nicholas Papalia and Associates (“Papalia”), an expert technical advisor in the oil and gas industry with lengthy experience in valuing Southern’s interests, and a firm of sharebrokers then called Buttle Wilson (later SBS Warburg: “Warburg”) to advise them and, through them, the minorities.
[5] Papalia 1– later detailed – valued Southern’s proved and probable reserves3 at
$79.63m and its exploration interests at $10.14m. Using the Papalia data amongst other sources, Warburg 1 reported to the independent directors on 14 August that the offer price of 63 cps for the 50 cent shares paid to 45 cents was fair and reasonable to minority shareholders.
[6] Relying on those reports and other material, on 16 August the independent directors recommended minority shareholders accept PIL’s offer.
[7] Notwithstanding that recommendation, a group of minority shareholders took the view the price was too low. Those shareholders included the present plaintiffs and a Mr Oakley, a Wellington solicitor who held a substantial parcel of Southern shares. Their actions in opposing the offer - including threatening litigation - will require later detailing but, for the purposes of this brief outline, it is sufficient to note that PIL declared the takeover offer unconditional on 29 August. On 4 September Fletcher Challenge agreed to transfer Petrocorp’s 194,178,500 Southern shares into the offer. That resulted in the Fletcher Challenge Group holding 92.97% of Southern’s capital by that date. On 15 September the offer closing date was extended to 29 September. It was later further extended to 13 October and then to 29
December.
[8] On 16 October the Crown jointly awarded Southern and Petrocorp five new onshore Taranaki Basin petroleum exploration permits with Petrocorp sharing with others in five offshore permits awarded the same day. Southern was entitled to share
3 See Annexure 1 for Definitions.
in the award to Petrocorp of the offshore permits through their Alignment Agreement later discussed.
[9] On 16 October Southern’s independent directors instructed Papalia and Warburg to advise on any increase in the value of Southern’s shares resulting from the award of the new onshore and offshore permits,
[10] On 16 November Papalia 2 valued the offshore and onshore awards at $33m pre-tax and $21.33m post-tax and on 17 November Warburg 2 reported that as a result of the permit awards the “fair value range per share paid to 45 cents has increased by 9 cents per share to 59-69 cents per share”.
[11] Those valuations must have been available to Fletcher Challenge a little earlier because on 15 November it increased PIL’s offer as a result of the revised independent valuations to 75 cps per 45 cents paid share. That followed the independent directors’ acceptance the previous day of the valuation range of
59-69 cps. They recommended acceptance of the revised offer.
[12] On 15 November Mr Oakley accepted the increased offer. When they learned of his acceptance, most of the remaining minority shareholders followed suit over the period to 24 November. PIL served a notice under s 208(2) of the Companies Act 1955 on 18 December to acquire the balance of the shares compulsorily at 75 cps. The compulsory acquisitions were complete by 19 January
1996. The increased price was paid to all minority shareholders irrespective of their date of acceptance. From 30 January 1996 PIL became the holder of 228,922,944 shares, being all the shares in Southern, and the company was de-listed.
(2) The 2 November 1995 Presentation in Outline
[13] That is no more than the sketchiest of outlines of the facts on which this case is founded - but on which a considerable edifice of litigation has been constructed. Beginning in 1999, it passed through a significant number of interlocutory stages
- few of which require recounting – to culminate, at this point at least, in the 30-day hearing listed on the frontispiece. Though it will be necessary to discuss relevant
matters in detail, it is sufficient, to set the scene, to say the claim is one alleging insider trading under the Securities Markets Act 1988.4 In essence, the plaintiffs claim that while the contested takeover was in progress the Deep Gas Study Team (“DGS Team”), employees of Petrocorp, were in possession of information which was price-sensitive so far as the value of Southern’s shares was concerned and that at a presentation on 2 November they made that information – called in the case the “Mangahewa Information” – available to executives of, broadly, the Fletcher Challenge Group. Those executives are alleged to have failed to make that
information available either to the reluctant shareholders or generally and, as a result, Southern’s shareholders received less for their shares than would have been the case had the Mangahewa Information been publicly available.
[14] There was a wealth of evidence concerning the 2 November presentation which requires detailed examination but, again to set the scene, the Mangahewa Information essentially consisted of about 90 slides shown to a group at Petrocorp’s New Plymouth offices on 2 November as part of a “Technical Presentation” entitled “Deep Gas Project”.
[15] Slide 18, one of a number that referred to the Mangahewa Structure or
Formation, read: 5
MANGAHEWA STRUCTURE
• World Class size
• ~150 km2 areal closure
• ~105 km3 gross rock volume
Multi-TCF6 potential
4 All statutory references in this judgment are to the Securities Markets Act 1988 unless otherwise specified.
5 See Annexure 2 for definitions of relevant technical terms.
6 TCF = Trillion Cubic Feet.
[16] Slide 76 read:
MANGAHEWA STRUCTURE INDICATIVE VOLUMETRICS
Mangahewa Structure GIIP7
Summary Volumetrics
McKee Formation TCF >9% porosity
33%
1.2
<9% porosity 67% 2.5
Resource size is not an issue
Total: 3.7
Mangahewa Formation TCF
>9% porosity 36% 6.8
<9% porosity 64% 12.1
Total: 18.9
Both Formations TCF
>9% porosity 36% 8.0
<9% porosity 64% 14.5
Total: 22.58
while Slides 86-87 read:
7 GIIP = Gas Initially In Place.
8 3.7+18.9=22.6 – Where appropriate, the corrected figure is used in this judgment.
Interim Conclusions
Deep Gas is the target
Appraisal phase
Will fill demand wedge
Mangahewa Structure is the place to drill
Humungous
Most Well and Seismic Control
Largest Potential Gross Gas Pay Section
PPL 38705 Expiring July 31, 1998 8
Offshore Continuation
No perceived free water
Gas Resource Confirmed
Petrophysics conclusive
Testing conflicting
Permeability
Not Tight Gas
Fraccing10 needed
Continuity/Well Drainage
McKee Continuous
[17] As will already be apparent the case involved a significant number of disparate facets, many of them technical, which may, initially at least, seem disconnected - but all of which ultimately bear on the issues outlined.
Parties
[18] Under the Securities Markets Act 1988 the leave of this Court is required to permit persons, including former shareholders, to bring an insider trading claim exercising the rights of the company in which they formerly held shares.
[19] In this case, leave was granted by Fisher J on 18 June 2002 (Haylock v
Southern Petroleum NL [2002] 3 NZLR 518). The plaintiffs in this case are the
8 PPL 38705 = Petroleum Prospecting Licence.
10 The name commonly used for hydraulic fracturing or stimulation of a well.
remaining three of the four who were ordered to be named as individual plaintiffs in a second decision (Haylock v Southern Petroleum NL (No.2) [2002] 3 NZLR 819). Both decisions went to the Court of Appeal (Haylock v Southern Petroleum NL [2003] 2 NZLR 175).
[20] The parties to this claim have changed over time. Until 29 February 2008, when leave was granted for him to discontinue his claim, the fourth plaintiff was Mr Oakley. One reason for the claim taking as long to reach a substantive hearing as it did was because there were deep divisions between the present plaintiffs and Mr Oakley as to how the claim was to be presented, divisions which were deep enough for the two camps of plaintiffs to instruct, at times, separate senior counsel and separate solicitors and, for a period, a special partnership firm of solicitors formed solely to manage this claim. Fixtures for November 2004 and April 2005 were vacated, principally because of divisions between the camps of plaintiffs.
[21] The first defendant, Mr Patek11 was Chief Executive of Petrocorp 1986-1990, and Chief Executive of Fletcher Challenge Petroleum (“FC Petroleum”) 1990-1996, and a director of Petrocorp, Southern and PIL during the period principally in issue in this claim.
[22] Shell Exploration NZ Ltd became second defendant following what appears to have been either an amalgamation or sale of Fletcher Challenge Energy to Shell - strictly Shell Overseas Holdings Ltd and Apache Corporation - after 10 October
2000.
Statute
[23] The claim was brought under the insider trading régime introduced by the Securities Amendment Act 1988 (which also changed the name of the principal Act to the Securities Markets Act 1988) but which was repealed from 29 February 2008 on the coming into force of the Securities Markets Amendment Act 2006.
11 See Annexure 3 for potted biographies of witnesses not described elsewhere in the judgment.
[24] Southern, being listed on the NZX, was a “public issuer” under the Act. “Insider” was relevantly defined by s 3:
3 Meaning of insider
For the purposes of Part 1, insider in relation to a public issuer, means
(1) (a) the public issuer:
.
(b)a person who, by reason of being a principal officer, or an employee, or company secretary of, or a substantial security holder in, the public issuer, has inside information about the public issuer or another public issuer:
(c)a person who receives inside information in confidence from a person described in paragraph (a) or paragraph (b) about the public issuer or another public issuer:
and s 3(2) added:
(2)For the purposes of paragraph (b) of subsection (1), a principal, officer, or an employee, or company secretary of, or a substantial security holder in, the public issuer, who has inside information about the public issuer or another public issuer is presumed, in the absence of evidence to the contrary, to have that inside information by reason of being a principal officer, employee, company secretary or substantial security holder.
[25] Section 2 defined “substantial security holder” in relation to a public issuer as a “person who has a relevant interest in 5% or more of the voting securities of that public issuer” and “voting security” as meaning a “security of the public issuer … which confers a right to vote at meetings of members or shareholders”, subject to exceptions and qualifications not presently relevant. It also included directors within the definition of “principal officer”.
[26] Section 2 also defined “inside information” as:
Inside information in relation to a public issuer, means information which – (a) Is not publicly available; and
(b) would, or would be likely to, affect materially the price of the securities of the public issuer if it was publicly available.
[27] That meshes with s 9(1)(a), the section on which all causes of action are based, which relevantly read:
9 Liability of insider for tipping about securities of a public issuer
(1)An insider of a public issuer who has inside information about the public issuer and who –
(a) advises or encourages any person to
(i) buy or sell securities of the public issuer; or
(ii) advise or encourage any other person to buy or sell securities of the public issuer; …
…
(2) The persons to whom the insider is liable are –
(a) any person who sells securities of the public issuer to a person who is advised or encouraged by the insider to buy securities of the public issuer for any loss incurred by that person
(b) any person who buys securities of the public issuer from a person who
is advised or encouraged by the insider to sell securities of the public issuer for any loss incurred by that person
(c) any person who sells securities of the public issuer to a person referred
to in subsection (1)(a)(ii) who is advised or encouraged to buy the securities for any loss incurred by that person:
(d) any person who buys securities of the public issuer from a person referred to in subsection (1)(a)(ii) who is advised or encouraged to sell the securities for any loss incurred by that person:
(e) any person who sells securities of the public issuer to a person referred to in subsection (1)(b)(i) or(ii) for any loss incurred by that person:
(f) any person who buys securities of the public issuer from a person referred to in subsection (l)(b)(i) or (ii) for any loss incurred by that person:
(g) the public issuer for -
"
(i) any consideration or benefit received by the insider; and
(ii) any gains made, or losses avoided, by the persons referred to in subsection (2) in buying the securities from selling them to the
persons to whom the insider is liable …
(3)The maximum amount for which an insider is liable under paragraphs (a) to (f) and (g)(ii) of subsection (2), combined, shall not exceed the greater of the separate amounts for which the insider is liable.
[28] The references in s 9(2) to “loss” and “gain” also mesh with s 15 which reads:
15 Certain terms defined in relation to extent of liability of insider
(1) for the purposes of this Part, -
(a) a person who sells a security in a public issuer for less than its value incurs a loss equal to the difference between the value of the security and the consideration receivable:
(b) a person who buys a security in a public issuer for more than its value incurs a loss equal to the difference between the consideration payable and the value of the security:
(c) a person who buys a security in a public issuer for less than its value makes a gain equal to the difference between the value of the security and the consideration payable:
(d) a person who sells a security in a public issuer for more than its value avoids a loss equal to the difference between the consideration receivable and the value of the security.
(2)In this section value, in relation to a security in a public issuer, means the value the security would have had at the time of the sale or purchase if the inside information known to the insider about the public issuer was publicly available.
[29] Section 18 provided that the public issuer’s right of action against an insider could be exercised by security holders or shareholders but only with leave of the Court, leave which was not to be granted unless the Judge was satisfied that the public issuer had no arguable case against the insider or there were other good reasons for not permitting the action.
Pleadings
[30] What, against that background, is pleaded?
[31] The hearing proceeded on a claim dated 31 July 2006 and defences dated
4 February 2008.
[32] The statement of claim is lengthy but since the first 39 pages and 143 paragraphs do no more than recount factual allegations common to all eight causes of action and these are elsewhere discussed, it is convenient to focus on the pleading of the causes of action themselves.
[33] Observations needing noting concerning the claims include:
a) In a number of causes of action, pecuniary penalties were initially sought but were not pursued by the plaintiffs, they accepting those claims were statute-barred (Securities Commission v Midavia Rail Investments BVBA [2007] 2 NZLR 454, 460 para [21]).
b)Without notice, in his closing address, Mr Judd QC, senior counsel for the plaintiffs, abandoned the first two causes of action, both against Shell. Although not adverted to by counsel, that potentially might raise a difficulty in that those causes of action pleaded the Mangahewa Information in different and rather more extensive terms than the Mangahewa Information pleaded in relation to the remaining causes of action. This may have been inadvertent. Further, as will be seen, it is not easy to correlate the pleaded Mangahewa Information in the remaining causes of action with the 2 November slides.
c) In closing – confirmed by later memorandum – Mr Judd said if the plaintiffs succeeded on their first two pairs of claims against each defendant – third and fifth against Mr Patek and fourth and sixth against Shell - it was unlikely their position would be assisted by succeeding on the third pair – seventh against Mr Patek and eighth against Shell. But, should the plaintiffs need to rely on the third pair, an amendment was sought that “during the period 7-14 November, by negotiating with Mr Oakley to persuade him to sell his shares, Mr Patek advised and encouraged PIL to buy the shares in SPNL not already owned by Petrocorp [sic]”, and that during the same period through Mr Patek’s actions, “Petrocorp advised and encouraged PIL to buy the shares in SPNL not already owned by Petrocorp” [sic]. Since Fletcher Challenge agreed to transfer Petrocorp’s shares in Southern on 4 September, “PIL” may have been intended for, or in addition to, “Petrocorp” in those forecast amendments. A further amendment was forecast in confidence alleging Mr Patek received the Inside Information from Petrocorp not Southern. No response was received from the defendants concerning Mr Judd’s applications.
d)Mrs Haylock, the first plaintiff, reluctantly sold her 10,000 Southern shares to PIL on 10 October at 63 cps. The remaining plaintiffs, Mr Cairns and Hugh Green Properties Limited (formerly Green & McCahill Properties Ltd) sold theirs or those of their interests,
810,300 shares, on 15 November at 75 cps. In all causes of action other than the first against Mr Patek – third in the amended claim – the relief sought is for the gains made by PIL in buying Southern shares from Mr Cairns and Hugh Green Properties and the other shareholders in Southern after the respective dates pleaded in those causes of action. In the first cause of action against Mr Patek, however, the relief sought is for the gains made by PIL in buying Southern’s shares “from the plaintiffs and the other shareholders” on the respective dates. No difference may have been intended in the relief sought.
[34] The three extant causes of action against Mr Patek, (third, fifth and seventh in the amended claim) all plead he was an insider of Southern between 31 May
1995-19 January 1996 under s 3(1)(b)(c) as a Southern director and that he had price-sensitive information about Southern that was not publicly available, or he received the Inside Information from Southern in confidence. The variations between the three causes of action are that Mr Patek advised and encouraged PIL to buy the Southern shares not already owned by Petrocorp, PIL or subsidiaries by :
a) Recommending to the Fletcher Challenge sub-committee on
3 November that PIL increase its offer to 75 cps.
b)Requesting the assistance of Mr Mace, a member of the Fletcher Challenge sub-committee overseeing the takeover, to persuade that sub-committee that PIL should increase its offer to 75 cps and recommending that to the sub-committee, all on 5 and 6 November.
c) Recommending to the Fletcher Challenge sub-committee on
14 November that PIL increase its offer.
[35] The three extant causes of action against Shell (fourth, sixth and eighth in the amended claim) all plead that from 31 July 1995-19 January 1996 Petrocorp was a Southern insider under s 3(1)(b)(c) as a substantial security-holder in Southern with price-sensitive information about Southern by reason of that position, which was not publicly available, or that it received the Inside Information from Southern in confidence. The variations are that Petrocorp advised and encouraged PIL to buy the Southern shares not already owned by those companies or subsidiaries by, as alleged against Mr Patek, his actions on 3, 5 and 6, and 14 November recommending to Mr Mace and the Fletcher Challenge sub-committee that PIL increase the offer to 75 cps.
[36] All six extant causes of action define the Inside Information as, first, the Mangahewa Information; secondly, that Papalia and Warburg did not have access to the Mangahewa Information and accordingly all their advice to Southern as to the value of its assets was based on only part of the information to which Southern was entitled; and thirdly, the effect knowledge of the Mangahewa Information would have had on public perception of Southern’s assets and share values and continued resistance by the reluctant shareholders to the takeover which would have led to the Mangahewa Information being made publicly available over time and oblige PIL to pay more than it did for the minority shares.
[37] All extant claims defined the “Mangahewa Information” as material obtained by the Deep Gas Study between June 1995-15 November 1995 concerning exploration prospects and including:
• “The evidence indicating the Mangahewa structure within PPL 38705 was potentially 4 to 7 times larger than Maui;
• The identification of the Mangahewa structure which lies within the territory of PPL 38705 as suitable for use of stimulation technologies, including hydraulic fracturing.
• The assessment of the probability of recovering hydrocarbons at an economic return;
• The assessment that the Mangahewa Structure was the most likely prospect in onshore Taranaki;
• The proposal by the Deep Gas Team that the joint venture for PPL 38705 drill Mangahewa 2 commencing date of 1 March 1996;
• The fact that gas discoveries made between 1994 and 2000 could provide a commercial opportunity with regard to power stations and the Methanex plant;
• The fact that the Fletcher Challenge Group intended to be the dominant entity controlling the supply of gas within New Zealand;
• The fact that the Mangahewa Structure could provide Methanex with a future supply of gas at a time and price acceptable to Methanex; and
• The identification by the Deep Gas Team that the Pohokura prospect situated in Block S was essentially a northward offshore extension of the Mangahewa structure.”
[38] Shell’s defence admitted Petrocorp was a substantial security-holder in Southern during the pleaded period but denied it had price-sensitive information about Southern by reason of its position as a substantial security-holder that was not publicly available and denied it received any Inside Information from Southern in confidence.
[39] Mr Patek admitted his directorship of Southern during the pleaded period but he, too, denied he had information about the company by reason of his position as a director that was not publicly available and would have been price-sensitive, and denied he received any Inside Information from Southern in confidence.
A Little Geology
[40] Both Southern and Petrocorp were E & P companies operating principally in New Zealand in the Taranaki Basin. That is the name geologists give to that part of the New Zealand sub-continent extending in an arc from beyond Kawhia in the north, through inland Taranaki, to beyond Tasman and Golden Bays in the south. It is bounded on the east by the Taranaki Fault and extends well west into the Continental Shelf. Prior to 100m years ago the nascent Taranaki Basin was on the eastern seaboard of Gondwanaland adjacent to the present Bass Strait. The triple junction between the Australia, Antarctica and Pacific plates and tectonic forces led
to oceanic floor spreading between 80m and 55m years ago, creating the New Caledonia Basin to the north and the Bounty Trough to the south. At much the same time, beginning about 85m years ago in the late Cretaceous, the New Zealand land mass drifted east with large faults developing and down-warping of the surface beginning the creation of the Taranaki Basin.
[41] Over geological time, sediment eroded from mountainous regions was deposited near the then coast by rivers whose courses changed as they meandered across the peneplain. Lagoons and lakes developed and became, today, partly interconnected sandstone reservoirs. Organic-rich sediments deposited in the estuaries and lagoons were buried over time and the breakdown of biological material deposited in the Basin over geological time was then subjected to massive pressure as it was more deeply buried, in time producing water, carbon dioxide, oil and gas, particularly methane.
[42] This pattern continued until the end of the Eocene about 34m years ago, but the deposition continued until the mid-Miocene period, about 15m years ago, when subduction of the Pacific Plate compressed the Taranaki Basin rocks and reactivated late Cretaceous Faults forcing large blocks of sediment upwards.
[43] This process created anticlinal folds which trapped hydrocarbons and later resulted in hydrocarbon discoveries as oil or gas migrated upwards, collecting beneath an impermeable layer.
[44] At much the same time movements in the Taranaki Fault caused slivers of sediment to form thrust belts which also trapped hydrocarbons.
[45] Fluctuations in sea levels over geological time also affected deposition.
[46] The Taranaki Basin rocks reached their deepest burial about 2m years ago before significant uplift and tilting occurred.
[47] The Basin now lies further below contemporary sea level than Aoraki/Mount
Cook (3754m) is above it. It may be pertinent to note the entire period of deposition
long preceded the volcanic land forms now so dominant in the contemporary
Taranaki landscape: they arose between 2m and about 100,000 years ago.
[48] Much of the geological evidence in this case dealt with the Mangahewa and McKee formations in the upper part of the Kapuni Group laid down 66m-35m years ago.
[49] The Kapuni Group comprises the McKee and Mangahewa Formations plus the Turi and Kaimiro Formations. The McKee Formation is a sandy unit to the east of the Mangahewa Structure probably overlying its eastern flank. The Mangahewa Formation is the thickest of the Eocene deposits and is a body of rock comprising interbedded sandstones, siltstones and coals probably deposited as a uniform blanket across the area. The Mangahewa Structure is a large, closed, low-relief anticline,
15km long, 8km wide, with a total relief of 240m and an area of 150km2.
[50] The three pages of Annexure 4 show the location and shape of various permits and licences mentioned in evidence - including PPL 38705, that covering all or most of the Mangahewa Structure - and the location of the seven wells drilled on the Mangahewa Structure before 1995. It was first mapped in the mid-1950s. Mangahewa 1 spudded (ie drilling commenced) on 1 November 1960 drilled to
4285m. It established the Structure was a low porosity/low permeability (known in the industry as “tight”) reservoir gas/condensate trap system. Mangahewa 1 produced 1.5-2m standard cubic feet of gas per day (scuf/d) but, by contrast with the Kapuni-1 well in what became the Kapuni field, which produced 254scuf/d and
80 bbl/b (barrels)/scuf/d condensate, it was obvious Mangahewa 1 was of sub- commercial value. It was abandoned in 1974. The other six wells drilled in the Mangahewa Structure all encountered gas, but, again, not in economically recoverable commercial quantities and showed high water saturation. Mobile water within a tight gas reservoir, irrespective of volume, can make extraction economically impossible.
Prior to July 1995
[51] Governments of the day initially undertook oil and gas E & P activities in New Zealand principally through Petrocorp which was formed in 1978. Its task was to explore sedimentary basins around the country. By the time Petrocorp was sold to Fletcher Challenge in 1988, Petrocorp had spent over $200m in seismic and drilling operations onshore and offshore but only one, the Taranaki Basin, was commercially capable of recovering cost. Commercial successes included the McKee and Waihapa Fields, discovered in 1979 and 1987 respectively, but against that there had been a number of failures including all those drilled into the Mangahewa Structure, none of which achieved commercial production.
[52] In 1992 Petrocorp settled on an exploration strategy which was approved by FC Petroleum in November that year. One of the challenges was defined as “Refinement and Execution of the Play-Based Exploration Programme”.
[53] Petroleum prospecting in New Zealand has always been carried on under PPLs. They cover defined areas, either onshore or offshore. They run for five years. They require certain work programmes to be effected during their currency. PPL 38705 was originally issued to New Zealand Petroleum Ltd on 9 August 1988.
[54] By 28 April 1992 Southern owned 30% of PPL 38705 and on that date acquired a further share.
[55] On 2 June 1993, Petrocorp, Southern (44.5% each) and the Minister of Energy (who retained an 11% carried interest) entered into a Joint Venture Operating Agreement constituting a joint venture between the parties and appointing Petrocorp as Operator of PPL 38705, that is to say it undertook the day-to-day management and provided technical expertise to the joint venture.
[56] On 18 June 1993, Petrocorp and Southern signed an Alignment Agreement covering the various PPLs and Petroleum Mining Licences (“PMLs”) they held in the Taranaki Basin. In the industry, arrangements whereby licensees share each others‘ licences are known as “farm-in” and “farm-out” agreements. The Alignment
Agreement was a farm-in/farm-out agreement of the parties’ respective interests in various PMLs and PPLs – including PPL 38705 – and also gave each the right to farm-in up to 50% of any future permits the other might obtain. In that latter regard, cl 10.1 obliged the parties to “regularly consult with one another for the purposes of exchanging information” concerning any proposed bid for additional permits, and cl 10.2 debarred such bids by either “without first offering the other the opportunity to participate” in up to half the interest sought. In the event of breach of those provisions the party obtaining further permits was obliged, by cl 10.3, to “offer to assign to the other half of the interest so acquired”.
[57] It was put to some witnesses, particularly Mr Humphrey, experienced in the oil gas and energy industries and from 1991-2000, the manager of strategic planning in Fletcher Challenge, that Petrocorp’s bid for the additional licences awarded on
16 October was in breach of cl 10 through it failing to offer half the interests acquired to Southern. The difficulty confronting that argument, however, was that, as the Ministerial announcement of the awards of those permits showed, all the onshore grants to Petrocorp were jointly with Southern. True, the offshore grants in which Petrocorp was involved did not mention Southern, but Southern would have been entitled to share in them as a result of the Alignment Agreement. In any event, Papalia 2 valued Southern’s interest in all the Petrocorp permits awarded on
16 October, including those to which it was entitled through the Alignment
Agreement.
[58] Entering into arrangements such as the Alignment Agreement were part, Mr O’Connor, a former Petrocorp geologist and a witness for the plaintiffs, said, of Petrocorp’s aggressive exploration strategy. Its first step was to acquire interests in most licence areas in New Zealand. Its “Gas Strategy” was sparked by forecast decline in production from the Maui field. Mr O’Connor said Fletcher Challenge’s aim was to dominate the gas supply market that would open up as Maui production declined.
[59] In April 1994 the Petrocorp onshore property team prepared a paper defining the challenges to the Gas Strategy programme as including to “develop and follow
hypothesis-driven exploration programme” which included “Deep Oil and Gas
Prospects Upgraded” and “Gas Programme Accelerated”.
[60] Maui production was so considerable that gas exploration declined from its discovery in 1969 (with Kapuni a decade earlier) throughout the 1970s and 1980s in favour of oil exploration. Maui was then thought more than adequate to supply the market until well into the 21st century. (Diverting briefly, the evidence was that while, worldwide, wells are drilled for oil without known buyers – indeed, some are drilled on a “wild-cat” basis – exploration wells seeking gas are usually drilled only when buyers for discoveries are known). However, by the early 1990s forecasters were suggesting a replacement for Maui gas needed to be found within the next decade to provide long-term security for the gas market and, particularly, to supply Methanex, the largest industrial gas buyer. Its supply contract extended until 2003 but, from about 1994 onwards, there was concern that in the absence of secure future supply Methanex may curtail its production and close one of its two methanol plants. Indeed, on 6 October 1995, Methanex confirmed that position in a public statement.
[61] Mr Logan, an engineer, general manager and director of Petrocorp and a Southern director during the relevant period, said Methanex’s statement confirmed what the industry had known for some time. He made the point that a Methanex closure would have had a major financial impact on FC Petroleum which relied on the significant income from Methanex’s off-take of Maui gas and condensate.
[62] On 21 June 1994 the work programme under PPL 38705 was amended to require, amongst other things, drilling a well and reviewing the “potential gas productivity of Kapuni Group sandstones in existing wells” including the “likely effectiveness of reservoir stimulation techniques” by 1 August or surrender of the licence. Additionally, prior to 1 August 1996, the work programme also required the drilling of a further well or, again, surrender of the licence.
[63] As a result of those matters amongst others, Petrocorp set up the DGS Team. Mr Crookbain, a Petrocorp geologist, convened a “framing” session on
14 September 1994 attended by Petrocorp management. It proposed an onshore
Taranaki Deep Gas Project to “confirm the value of onshore Taranaki Gas
Potential”, to obtain better understanding of the geological and business issues and to co-ordinate Deep Gas activities across some eight Deep Gas Kapuni Group projects, including PPL 38705. A paper dated 5 October 1994 to Petrocorp and Southern in support of an AFE (“Authorisation For Expenditure”) of $313,685 to be split evenly conveys the flavour:
The offshore Maui field currently dominates New Zealand’s gas supply, though the contract price for Maui gas is considerably below world market levels. This situation has undermined the commerciality of gas exploration in the Taranaki region. However, by the year 2001, Maui production will come off plateau and will fall rapidly. It is considered that over the next 5-
8 years a market for new gas supply will emerge.
Gas has been encountered in many exploration wells drilled to the deeper parts of the Taranaki basin. However, with the exception of the Kapuni and Maui fields, reservoir quality is poor and gas flow rates on test have not reached commercial thresholds.
However, the recent fracture stimulation of the Kaimiro field has shown the potential for enhancing the productivity of poor reservoirs and it is now considered timely to take stock of the future gas potential of the Taranaki basin. The 1992 Strategy study identified the considerably lower costs associated with onshore gas developments as opposed to those located offshore. Therefore, it is proposed that this study is restricted to evaluating the gas potential of onshore Taranaki.
[64] Results of the Deep Gas Study would include maps of the reservoirs and recommendations regarding future drilling and commerciality.
[65] Mr Crookbain was initially the only Petrocorp employee dedicated to the Deep Gas Study and, despite his geological efforts and his, largely unsuccessful, efforts to convince management to provide additional resources, it fell behind schedule. As a result, he and Mr Webster, Petrocorp’s chief onshore geologist, met on 1 December 1994 and decided the team would spend the next few weeks focusing on the Mangahewa anticline and the Ohanga Thrust in PPL 38705 because, as far as Mangahewa was concerned:
The Mangahewa anticline remains the largest non-producing Kapuni structure onshore. None of the historical or recent mapping indicates that larger scale features have been overlooked. The structure is well placed for charge, and our feeling is that if we don’t gain an understanding of why this structure didn’t work initially, and what is required to make it work, then there is little value in chasing smaller features at this time.
Mr Webster obtained approval from Petrocorp exploration management for the move.
27 July 1995 – 2 November 1995
[66] It is unnecessary to detail the DGS Team’s work over the next few months save to note that prior to a Technical Review Team (“TRT”) meeting on 27 July, reports created included a stratigraphic report on a number of prospects and leads within the Kapuni Group and a sedimentological report analysing core samples from exploration wells and covering depositional characteristics. Thirdly, a petrophysical examination reviewing all wells drilled on the Mangahewa Structure confirmed that onshore Kapuni Group penetrations outside of the Kapuni and McKee fields were low quality reservoirs with poor permeability. Drilling data from onshore wells had been collected and Mr Wolter, a Petrocorp geophysicist, had reviewed seismic interpretations in order to map Mangahewa. Maps delineated the shape and elevation of the Mangahewa and Ohanga Structures at top McKee Formation level but were unsuitable for volumetric estimation.
[67] In addition, Petrocorp commissioned a report from the Centre for Petroleum Engineering at the University of New South Wales on the Kapuni Group. Professor Khurana concluded there was a “high probability of gas reserves in the range of
100-300bscf being present in the equivalent of the McKee/Mangahewa Formations” but that “overcoming the long term detrimental effect of retrograde condensation on well productivity through hydraulic fracturing would be difficult”. Water saturation, or “mobile water”, was foreseen as a problem since all Deep Gas wells in onshore Taranaki, with the exception of Kapuni, had co-produced water with gas.
[68] The TRT met on 27 July. Mr Dobbie, Southern’s geologist had, under the Alignment Agreement, been receiving regular project updates, onshore team reports and invitations to TRT meetings. He attended on 27 July. The meeting’s purpose was to review the work on gas accumulation in PPL 38705 and assess whether “uncertain Kapuni Group opportunities merit further technical resources at this stage”. The paper said there had been “significant development in our understanding of the structures in PPL 38705 and their reserves potential”, with the options being
either to complete documenting PPL 38705 to meet the work programme or to continue the study which will “likely result in a well or re-entry proposal and a lengthy testing programme” despite the resource implications.
[69] Mr Crookbain said a result of the meeting was a shift in approach by the DGS Team to production technology and reservoir engineering, disciplines which focus on optimising hydrocarbon recovery from reservoirs and wells. He said it was then thought any Mangahewa 2 well would be deferred until 1996 or 1997, though requiring to be reported to the Ministry of Commerce by 14 August. At that stage, he said, uncertainties included how potentially significant gas in the Mangahewa Structure was distributed and whether it was recoverable in default of a volumetric estimate of GIIP or reserves. Despite a preliminary approach to an overseas fraccing expert, nobody had been engaged to advise on reservoir stimulation and no economic modelling had been undertaken.
[70] Despite the flow of information, this would appear to have been the first meeting of the DGS Team attended by a Southern representative. Mr Dobbie said Southern was previously aware Petrocorp had identified Mangahewa as a possible drilling prospect and a formal proposal for a well could be forthcoming but knew, both generally and from what passed at the meeting, that the drilling of Mangahewa
2 was not definite until the full technical review was completed and a funding decision taken to proceed.
[71] As earlier noted, PIL’s takeover offer was issued four days after the TRT meeting but, for present purposes, it is logical to continue considering the Deep Gas Study before reverting to consider the takeover detail.
[72] Mr Wolter’s map of the Mangahewa Structure featured during this hearing. He did not give evidence but his affidavit opposing the leave application was put in evidence. It said that at a meeting of the DGS Team on 20 July the potential of the Managahewa Structure first became apparent through its sheer size but it presented the problem that poor quality of the reservoirs precluded economic gas flow. He produced his first version of the top McKee sandstone reservoir depth map on
5 August. It showed the Structure but said nothing about gas accessibility.
[73] Mr Patek conducted quarterly performance reviews (“QPR”) of Petrocorp at New Plymouth. One such took place on 17-18 August. The voluminous papers prepared for the meeting included three slides from the DGS Team which said it had “identified significant gas potential in Kaimata and Mangahewa Structures,” with a “production technology project planned”. They said there had been “significant advances in quantifying onshore Deep Gas value”. The onshore team’s objectives including the drilling of two exploration wells, with Mangahewa 2 deferred to
1996/97. Mr Patek said those terse comments were not elaborated upon and made little impact on him since deferral was proposed.
[74] Mr McCagherty also attended. He was a reservoir exploitation engineer of nearly 30 years’ experience in many countries and was employed by Petrocorp as its engineering manager from late May-early June 1995 to late August 1996. He described himself as someone who is “known for getting things done”, Mr O’Connor described him as “gung-ho” by contrast with the “paralysis by analysis” approach of some Petrocorp teams. Mr McCagherty played a significant role in the Mangahewa project..
[75] Mr McCagherty said when he arrived, although he found the calibre of the exploration staff high, there was a cautious corporate culture concerning exploration in the Taranaki basin and little experience of dealing with a tight gas play such as Mangahewa. The culture, he found, reflected not just the world-wide risk inherent in oil and gas exploration but also Fletcher Challenge’s unsuccessful investment in a number of wells in the Mangahewa Structure and around the world. He said he found Mr Patek, operations manager of Petrocorp when the seven unsuccessful wells were drilled on the Mangahewa Structure, particularly unenthusiastic about the prospectivity of onshore Taranaki exploration. That especially applied to gas exploration which was, at best, then only marginally economic in the New Zealand market because of the plenitude of Maui.
[76] Mr McCagherty found the Deep Gas Study proceeding on a low key basis and “stuck in limbo” on arrival. He felt adding his engineering expertise could “provide the drive and enthusiasm to actually take hold of the project and carry it through to fruition (which meant to drill a well or drop the project)”. From July he
ensured the Deep Gas Study focused more on PPL 38705 as the largest potential resource. His “sole” objective was to get sufficient funds to drill and complete two wells, one to prove the concept, the second to duplicate the results. He found the DGS Team had by then mapped other structures but not Mangahewa though the petrophysical and stratigraphic data had identified the principal uncertainties for the Structure. He made the point the DGS Team had not generated any new data or used new techniques: the data on which it had worked was well-known (and public, through Ministry of Commerce reports) and it was not until the later detailed Assessment Well Proposal of June 1996 that the drilling proposal fully crystallized. He also made the point that, as development manager, he had every incentive to book all the reserves and value onshore he thought was justifiable because it affected his bonus. He would have booked reserves for Mangahewa if he thought an independent engineer would give it at least a P50 (proven plus probable) reserve valuation. As an exploration play, Mangahewa was valueless as a Southern reserve: reserves could only be called such and able to be ascribed value in the event of a successful well.
[77] At about the time of a TRT meeting on 6 October or shortly thereafter, the DGS Team may have moved from Mr O’Connor’s exploration team to Mr McCagherty’s engineering team. There had been longstanding tension between the teams. If that move did not happen at that point, it happened shortly afterwards, and although on 6 October the DGS Team was not entirely focused on Mangahewa, at Mr McCagherty’s urging Mangahewa quickly became its predominant focus and, after 15 November at the latest, its only focus.
[78] The 6 October meeting followed further extensive technical assessments of the numerous uncertainties posed by Mangahewa, reviewed the forward work plan and discussed the Deep Gas well proposal. Mr McCagherty, whose Canadian experience led Mr Webster to describe the newcomer’s approach as “more instinctive” and “far more activity focused” than the Petrocorp scientists, was enthusiastic about the possibility of obtaining funding for any proposed well. Longer-serving Petrocorp executives remained guarded, consistent with the letter
Mr Webster sent Mr Dobbie on 6 October seeking Southern’s approval of the work programme and budget saying:
The Deep Gas review has been largely completed. The mapping has confirmed the Mangahewa structure as a valid structural closure with considerable reserves potential. The critical factors for success appear to be drilling and testing/completion techniques and we will be continuing work on these aspects after the report is lodged. Our assessment of gas market opportunities indicates that we have a 12-18 month window in which to demonstrate a sustainable gas supply beyond 2005, although we are unlikely to access the market until ~ 2007.
[79] Mr O’Connor’s letter only proposed a POP12 for Mangahewa 2 of 33% which led Mr Dobbie to infer a substantial amount of work remained before the joint venture would be asked to commit to drilling Mangahewa 2. His response of
10 October agreed on acceleration of the exploration programme within the remaining life of PPL 38705 and queried whether Petrocorp actually intended to undertake all activities shown in the programme over the remaining nine and a half months. Mr Webster reassured him on 14 October that the Deep Gas Study was in parallel and “will be concluding before year end with a likely drilling recommendation”.
[80] Mr Crookbain, however, said the Deep Gas Study changed focus after the 6
October meeting once Mr McCagherty had effectively taken over. Further resources were allocated. Momentum increased. The mapping, petrophysical and engineering studies were synthesised to put the test results of the previous Mangahewa wells into context, especially as regards low flow rates and co-production of water with gas.
[81] By 20 October the onshore team monthly report said “good progress has been made on the review of drilling and testing issues associated with Mangahewa Structure in PPL 38705” with a plan for reservoir engineering and production technology being prepared and a possible well site located. Mr McCagherty explained the last comment by differentiating between the location for a well on the crestal part of the Mangahewa Structure rather than location of a site in the sense of a position derived from map co-ordinates.
12 POP = Probability of Proceeding.
[82] The situation to that point appears best summed up by Mr McCagherty:
Of course, we were in the business of exploration. Until you drill a well, you can never be sure of what is down there and whether oil or gas is able to be commercially recovered (ie reserves). Ultimately, we would never know what would or might be possible without sticking a well down. The more wells we drilled into the structure, the better we would understand what was down there. My experience with tight gas is that a number of wells are needed before you can quantify the true reserves, productivity and value potential of the play.
It was apparent that there was a lot of work to be done in relation to the Mangahewa prospect, including convincing the Auckland office that it would be worth exploring. However, I was of the view … that the Mangahewa prospect was very promising. I was motivated to push this project, and therefore worked with the team to review the data and put together the information necessary to get sign off from Auckland management.
[83] However, his approach was to go back to the beginning and review all the data. He did that because he said “we needed to understand why these wells failed before we went on to the next step which was: why was the eighth well actually going to succeed?”. By 20 October he said their plans were to look at the available information on the Deep Gas opportunity, assess the data and “see if there was an opportunity to drill an additional well that had a good chance of finding reserves”.
2 November 1995 Presentation in Detail
[84] Mr McCagherty said the impetus for the 2 November presentation arose from his desire to push for support for Mangahewa 2 even though he knew that by reason of cost and Petrocorp’s negative experience with deep wells there was likely to be considerable “push back” from Fletcher Challenge executives in Auckland. It was not a well-drilling proposal. Despite that, his strategy was to “get people talking about the opportunity” and he was keen to “test the waters” by making a preliminary presentation to management to, as he put it, “see if I can get some buy in or, at the very least, identify their key concerns so we can try and address them”.
[85] The meeting was called at short notice. It took place in the large Maui Room at Petrocorp New Plymouth and was attended by a number of people. Those present included, from Fletcher Challenge Auckland, Messrs Lammerink and Rawlinson. Most, if not all, of the other up to 15 attendees appear to have been Petrocorp New
Plymouth employees. Evidence suggested attendance waxed and waned as people joined or left. Nobody from Southern was invited though Mr Logan was present.
[86] As mentioned, the slide part of the presentation extended to 90 transparencies which, at Mr McCagherty’s suggested rate of progress, would have taken perhaps three hours or more to complete. In addition to the slides, there were apparently “montages” around the room. They seem to have been additional material on the same subjects but, since no witness could recall their content and the montages were unable to be discovered once the claim began, they pass from consideration.
[87] At 90 slides, the presentation is too long to attach to this judgment, although what seem to be the principal slides were earlier reproduced.
[88] The presentation began with Slide 2 listing the objectives of the meeting as being to “review the data set … structure the appropriate work plan” and discuss a Methanex meeting. The meeting outline (Slides 4 and 5) summarised the topics to be covered:
MEETING OUTLINE Gas Market Demand Taranaki Basin Potential Deep Gas Resource Exploration History
The Reservoir Performance Review Reserves Potential
Drilling completion Issues Possible Development Scenario Value Characterisation
Working the Problem
As might be expected, the slides then generally followed that topic order.
[89] The presentation had been compiled from work done by a number of experts in the various disciplines represented in the DGS Team and the persons responsible probably presented sections on which they were expert.
[90] In addition to the slides earlier set out:
a) Slides 12 and 13 on the “prospectivity of the basin” spoke of the “large potential” for deep gas being at the “appraisal stage”. That was followed in the same section by a slide saying “reservoir quality low compared to other plays in basin … productivity to date poor at best given capital costs” and that “appraisal well required to test productivity” including “fracture stimulate”.
[The area of a reservoir considered proved includes (1) the area delineated by drilling and defined by fluid contacts, if any, and (2) the undrilled areas
that can be reasonably judged as commercially productive on the basis of available geologic and engineering data.]
Proved reserves must have facilities to process and transport those reserves to market that are operational at the time of the estimate, or there is a commitment or reasonable expectation to install such facilities in the future.
Unproved Reserves
Unproved reserves are based on geologic and/or engineering data similar to that used in estimates of proved reserves; but technical, contractual, economic, or regulatory uncertainties preclude such reserves being classified as proved. They may be estimated assuming future economic conditions different from those prevailing at the time of the estimate.
[Estimates of unproved reserves may be made for internal planning or special evaluations, but are not routinely compiled.
Unproved reserves are not to be added to proved reserves because of different levels of uncertainty.]
Unproved reserves may be divided into two sub-classifications: probable and possible.
Probable Reserves
Probable reserves are less certain than proved reserves and can be estimated with a degree of certainty sufficient to indicate they are more likely to be recovered than not. The definition of possible reserves is not given as the term is not used in this report.
Possible Reserves
[Possible reserves are less certain than probable reserves and can be estimated with a low degree of certainty, insufficient to indicate whether they are more likely to be recovered than not.]
[ ] = omitted from Papalia 1.
[13] Mr Tearpock took the view that Mr Papalia’s letter of 4 September responding to Mr Oakley’s questions correctly demonstrated he regarded the Mangahewa gas at that point as “contingent resources” or “prospective resources”, not as “reserves”.
ANNEXURE 2
TECHNICAL TERMS DEFINED IN EVIDENCE
“Billion” In the US sense of 1000 million not the British sense of
1,000,000 millions
“BCF” Billion cubic feet.
“Connectivity” Defined by Mr Tearpock in the following terms:
“Connectivity” refers to where a sand body is in continuous communication or where it is separated by shale, faults, sand pinchouts, etc. Such geological factors can significantly impact the volume of hydrocarbons recovered from any individual well or reservoir, thus impacting the recovery factor and commerciality.”
Mr Crookbain also defined it as follows:
“Connectivity” describes the extent to which various reservoir bodies are actually in contact with each other to allow for the free movement of reservoir fluids towards a well. This is one of the factors which determines the reserves that an individual well can produce.”
“Darcy” “Darcy” – named for H P G Darcy (1803-1858) French
Hydrologist and Water Works Inspector.
A “darcy” is the unit of permeability to fluid flow being the permeability of a medium allowing a flow of 1 cubic centimetre per second of a liquid of 1 centipoise viscosity under a pressure gradient of 1 atmosphere/centimetre (Oxford English Dictionary 2nd ed Vol 4 p 247). 11 Darcys is commonly considered the minimum permeability for gas fields.
“Fraccing”(Hydraulic fracturing or stimulation) A number of definitions were put in evidence. For present purposes it is convenient to record that, in a paper by Dr Huckerby “Mangahewa Gas Programme” (1998 NZ Petroleum Conference Proceedings
81, 83):
“Stated simply the hydraulic fracturing process involves the pumping of fluids at high pressure into a target reservoir perforated interval to exceed the fracture strength of the reservoir and cause an artificial hydraulic fracture to form. Once this fracture has been initiated, a medium, called proppant (usually some kind of medium-grained sand) is pumped into the fracture to prop it open when the pumping is stopped.
… The placement of proppant in the fractures is assisted by the use of cross-linked gels. These are usually starch-based solutions, which are liquid at the surface but, with time and temperature, form long- chain polymer bonds and thus become like gels just before entry into the formation. Once in the formation these gels “break” back to a liquid state, so that they can be flowed back to surface without disturbing the proppant wedge, trapped in the hydraulic fracture. With continued flow, formation fluids should be drawn into the fracture, through the perforations into the wellbore and thence to surface.”
Mr Crookbain described the New Zealand experience of hydraulic stimulation or fraccing in the following way:
“6.17 By 1995 fraccing was commonplace in North America and Australia. However, New Zealand experience was fairly limited. Two Kapuni Group wells had been fracced in Taranaki in the early 1990s: Kapuni-15A (STOS) and Kaimiro-1 (Petrocorp), of which Kaimiro-1 was a tight reservoir. These were relatively small fracs, and were much smaller than anything that would be seriously contemplated for producing from a very low quality reservoir. The Kaimiro-1 frac did result in an improvement in gas production rates but the enhancement was relatively short lived, possibly for the reasons described above.”
Dr Haskell’s description of “fraccing” was rather more graphic:
“This process is called well stimulation. When you have restricted permeabilities there are two ways of mechanically increasing the permeability of the rock. One of them is to go in through the well bore … and isolate the zone which you want to stimulate and pump some very considerable and powerful acids … which will melt glass … and the combination of those two, very potent acids – but they are controlled
but it’s very dangerous stuff and you actually dissolve any clay material … so that it provides a bigger area for the gas to flow into the well.
“The second method does that in a straight mechanical method. You isolate the zone you want to increase the permeability of and line up a series of trucks with a special fluid, which … is quite viscous under pressure, but once the pressure is released, it stops being so viscous. Put these alongside a series of trucks full of a particularly stable type of sandgrain – it’s sand of a type which is … or can be stronger than quartz - and you pump a mixture down the well bore, which comprises a known mixture of these two things, and what it does is increase the pressure on the rock, to the extent where it actually breaks it. So, you get a fracture, hence the “fraccing”, a fracture, and literally, if you stand there you feel the whole thing go bang, and it just breaks, whatever the pressure may be, and they are horrific pressures, and … the fracture is filled by the combination of sand and liquid. … The pressure on the whole system is released, and the fill is pumped out … and the sand is left in that fracture zone in the rock … It just literally pops it apart. So, what you do,
… is increase the low permeability from just around the well bore to a hugely increased area, well back into the formation.”
“Gas Expansion Factor (GEF)”
The change in gas volume resulting from the change in
pressure and temperature from reservoir to surface conditions. Gas in the reservoir experiences higher temperature and pressure than at standard (surface) conditions. In Mangahewa this expansion was estimated to be in the order of a 290 fold increase.
“Gas Initially in Place (GIIP)”
Defined by Dr Haskell as the amount of natural gas in the
structure before production is undertaken. GIIP refers to the volume of gas estimated to be present in a particular sub- surface reservoir within a trapping structure. Whilst this volume represents all of the gas dispersed throughout the microscopic pores in the reservoir sandstone, not all of this will be retrievable from production wells drilled into this reservoir.
“Gross Rock Volume (GRV)”
The volume of rock containing hydrocarbons.
“Hydrocarbon Saturation (Sh)”
The percentage of the porosity filled with gas, whilst water
fills the remainder of the porosity, defined by the term water saturation (Sw).
“milliDarcy (mD)” milliDarcy = 1000th of a darcy.
“Net/Gross (N/G)”
The amount of net reservoir quality rock to the gross rock interval or the percentage of rock able to contain gas.
“Net Pay”
The fraction of the reservoir that will yield an economic flow of gas to the well. It depends on net-to-gross, porosity, gas saturation and permeability.
“P10 P50 and P90”
“P90” means that there is a 90% chance that the reserves will be equal to or greater than that value. P50 is that there is a
50% probability that they will be bigger or smaller. And P10 is that there is only a 10% chance that they will be larger or equal to the P10 value.
“Play”Defined by Mr O’Connor as “a series of prospects that have a common geological linkage”.
“POCS” Probability of Commercial Success of a well. (See “POGS”).
“POGS” Probability of Geological Success of a well was defined by
Mr Webster in the following way:
“POGS” is defined as the probability of discovering a hydrocarbon pool from which a measurable flow can be achieved. This would require a number of geological criteria to be satisfied – presence of reservoir, access to mature source rocks, presence of trapping mechanism and effective seal. POGS is an indicator of both the risk and the level of knowledge or
data available – in a frontier basin with few wells where the presence of an active hydrocarbon system has yet to be proved, POGS values are typically >10%, whereas in a more mature basin where petroleum systems are well understood and hydrocarbons have been proven, POGS will typically be in the 20-40% range. A POGS of 100% could only be applied to a structure that has previously been drilled and where the presence of hydrocarbons has been proven. POGS, however, gives no indication of the volume of hydrocarbons present, or the volumes that can be commercially recovered – this is defined as the probability of success (“POS”) or probability of commercial success (“POCS”).
“POP”“Probability of Proceeding” with a well. It was defined by Mr Webster as the probability of an operation (typically seismic or a well) going ahead.
“POS” Probability of Success (see “POGS”).
“Porosity”The percentage of the gross rock volume made up of pores between the mineral grains which defines the fluid storage potential of the rock. Conventional reservoirs have porosity in the 20-30% range, tight reservoirs often have porosity less than 10%.
“Prospect/Lead Play”
A prospect is an undrilled sub-surface feature that is
sufficiently well defined to estimate in place volumes and possibly locate a potential exploration well site, though the presence and volume of hydrocarbons is not confirmed until a well is drilled. A “lead” is generally less well-defined and needs further data or analysis to turn it into a “prospect”.
“scuf/d” Standard cubic Feet of Gas per day.
“structure”A structure is formed by a local warping of sub-surface rock layers, such that a local high point is created that acts as a collection point for any buoyant migrating hydrocarbons.
“tight”Reservoirs with low permeability and low porosity. As defined by the US Federal Energy Regulatory Commission (FERC), a tight gas structure is where in situ permeability to gas is less than 0.1mD.
“TCF” Trillion Cubic Feet.
“trillion” Defined by Dr Haskell as “trillion in the American and
European sense which is 1 x 1012 i.e. 1 followed by 12 zeros.
“Water saturation (Sw)”
Water adheres to the sand grains. Water saturation is the
percentage of the available pore space occupied by water measured as a percentage of the pore volume.
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ANNEXURE 3
POTTED BIOGRAPHIES
Mr Cimino:
Mr Cimino, now managing director of Dubai Financial Group, was managing director of an investment banking firm in New Zealand from 2001-2007 and, before that, with Warburg where he held a number of positions including chairman. He was formerly a board member of NZX and had served on the boards of a number of other companies. It was he who led the team that did the Warburg reports on the takeover offer in 1995.
Dr Haskell:
Dr Haskell has been involved in petroleum E & P for nearly 40 years and is a past president of the New Zealand Association of Petroleum Geologists. From
1973-1979 he was production geologist for Shell BP & Todd Oil Services Limited and then from 1980-1984 was at Petrocorp, first as chief geologist and later as exploration manager and general manager. When at Petrocorp he was responsible for the discovery and development of the McKee field and for the company’s operations offshore Taranaki and in the Great South Basins. He remains actively involved as an industry consultant.
Mr O’Connor:
Mr O’Connor, a geologist, was exploration manager for exploration for L & M Petroleum Limited, an E & P company listed on both NZX and ASX. He as previously an independent exploration risk assessor. He is a chartered geologist of the Geological Society of London, a Fellow of that Society and a certified petroleum geologist of the American Association of petroleum Geologists. He ahs 33 years
international experience in petroleum geoscience and has published widely on that topic.
Mr Patek:
The first defendant, Mr Patek, was Operations Manager of Petrocorp from August
1982 reporting to Dr Haskell, then general manager of the company. He held various positions in Petrocorp, including being its Chief Executive 1986-1990. He was then Chief Executive of FC Petroleum Ltd between 1990-1996 and then held other positions with Fletcher Challenge Energy up until 2000. Mr Patek was a director of Petrocorp 1988-1998, a director of Southern 1991-1998, and a director of PIL 1996-1998.
Mr Swindon:
Mr Swindon is an oil and gas advisor and investor of many years’ experience who, amongst many other achievements, has been a director of the Australian Petroleum Exploration Association, the Australian Mines and Metals Association and the Queensland Chamber of Mines.
Mr Tearpock:
Mr Tearpock is a highly experienced petroleum exploration and production consultant and author offering his company’s services in over 40 countries. He has had a lifetime involvement in the oil and gas exploration industry, has lectured and written widely on the topic, is a member of a number of geological and E & P societies, and is a committee member of the AAPG, the largest geological society in the world.
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ANNEXURE 4
MAPS
1. Taranaki Oil and Natural Gas Fields - attached as a PDF document.
2. Map showing Taranaki fields.
3. Scale map of fields: McKee, Kaimiro, Tariki, Stratford, Waihapa and
Kapuni.
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