Ithaca Energy (UK) Ltd v North Sea Energy (UK) Ltd (Rev 1)

The Claimant (“Ithaca”) and the Defendant (“NSE”) are participants, together with Dyas UK Ltd (“Dyas”) in the development of a small oil field in the Moray Firth called the Jacky Field. Their participating interests are, and were at the material time, Ithaca 47.5%, Dyas 42.5% and NSE 10%. From 2009 commercial quantities of oil were extracted from the field through Well J01. In April 2011 Well J03 was drilled pursuant to a decision taken by Ithaca and Dyas in December 2010 with which NSE disagreed. NSE claimed to be entitled to opt out of the obligation to contribute to the costs of Well J03. In these proceedings Ithaca seeks a declaration that the drilling of Well J03 constituted a joint operation for which NSE is obliged to contribute its share of the costs.

The participants’ mutual rights and obligations are, and were at that time, governed by an amended and restated Joint Operating Agreement dated 10 November 2008 as further amended by two supplemental agreements (the “JOA”). Under the terms of the JOA, NSE is entitled to opt out if, but only if, Well J03 was an “appraisal well” within the meaning of clause 14.2.2(ii)(d). The sole issue for decision in these proceedings is whether Well J03 was properly to be categorised as an “appraisal well” within the meaning of clause 14.2.2(ii)(d) of the JOA. NSE contends that it was. Ithaca contends that it was not.

I heard expert evidence from Mr O’Driscoll on behalf of Ithaca and Mr Rhys-Davies on behalf of NSE. Both were well qualified to explain the relevant practice which formed the background to the dispute and I found both to be helpful and fair witnesses. Where they disagreed it was because, in my judgment, there was a divergence of practice or opinion in the industry and they had had different experiences.

Both experts agreed that generally there are four different phases of oilfield activity, namely exploration, appraisal, development and production. Appraisal is that phase which is carried out after a discovery has been made by an exploration well, and before the oil company in question decides to apply to the relevant regulatory authority for permission to develop the discovery in question. Such application is made by the submission of a Field Development Plan (“FDP”). In the UK, the relevant regulatory authority was until late 2008 the Department for Business, Enterprise and Regulatory Reform and thereafter the Department of Energy and Climate Change (both are simply referred to as “DECC” in this judgment).

In an FDP the oil company making the application will set out a plan for the future development of the discovery, explaining the size and location of the oil accumulation believed to have been discovered; how the oil in that structure is proposed to be developed; the quantities of oil anticipated to be recovered pursuant to that development (on a low, a mid and a high case); the net present value of the revenues expected to be generated by selling those quantities of oil (usually discounted at 10%); what additional infrastructure and facilities the proposed development will require; and how much capital expenditure will be incurred in providing that infrastructure and those facilities.

In the event that DECC approves an FDP it will determine a Field Determination Area (“FDA”), being an area drawn around the oil accumulation which is the subject of the FDP. When this has been done, that area is referred to as a field.

Upon approval of the FDP the applicant oil company will then set about carrying out the development project set out in its FDP. When that project has been completed and the well or wells planned as part of that project have been drilled and are ready to be used for the production of oil, the oil company will apply for a permit to produce and the development phase will come to an end and the production phase will begin.

The appraisal phase of oil field activity is that phase which is preparatory to the decision to submit an FDP. It involves evaluating the discovered oil accumulation for the purpose of deciding whether it is likely to contain sufficient quantities of oil to make the expenditure required to develop that accumulation commercially viable.

But despite this apparently simple categorisation of wells drilled at the different stages of development of a field, appraisal activity is not limited to the phase in the life of an oil field which post-dates a discovery and pre-dates the submission of an FDP. The experts agreed that after the completion of the development phase and during production from a field, an oil company may consider various incremental projects, the ultimate purpose of which is to accelerate or increase the recovery of oil. The experts agreed that it is possible to have incremental exploration and incremental appraisal projects, as well as incremental production projects, after the field has gone into production. Both accepted that an appraisal well could be drilled within the boundaries of an FDA in the period after its determination by DECC. As a matter of industry practice, therefore, whether a project consists of appraisal activity, and whether a well is an appraisal well, is not conclusively determined by the fact that parts of the field have been the subject matter of development or production. The question whether a well is or is not an appraisal well cannot be answered simply by reference to the chronological stage of the exploitation of an oil concession.

What came to be known as the Jacky Field lies within block 12/21c in the Inner Moray Firth area of the North Sea. It sits adjacently to the north of the larger Beatrice Field, with both containing oil within a sandstone stratum known as the Beatrice A Sands. The two fields are, however, separated by a fault which hydraulically seals one from the other. In 1982 a well drilled by Britoil found hydrocarbons in the Beatrice A Sands sandstone reservoir in this structural feature adjacent to, but separate from, the Beatrice Field (“the Britoil Well”). The nature of the discovery was not at that time regarded as justifying further investigation or commercial exploitation, and no further steps were taken in relation to the discovery at that stage.

In March 2006, the UK Government granted Ithaca a Seaward Production Licence to “search and bore for, and get, Petroleum” in a number of blocks in the North Sea, including block 12/21c. The Licence was for an initial term of four years, and allowed for the extension of that initial term to include a second term, and a Production Period of 18 years. Clause 12 required the licensee, before the expiry of the initial term, to carry out a work programme, defined in Schedule 3 as including the drilling of one well to a specified depth. Clause 13 provided for a requirement to obtain development consent. Clause 15 required the licensee to obtain the consent of the Minister before drilling any well. Clause 17 required the licensee to obtain the approval of the Minister before carrying out completion work on any development well.

The first well to be drilled pursuant to the Licence was started in April 2007 and was designated well 12/21c-6 or well 12/21c-f. The well proposal document described the well classification as “appraisal”.

By a letter agreement dated 12 April 2007 between Ithaca and NSE, NSE agreed to pay 15% of the costs of drilling well 12/21c-6 in return for a 10% participating interest in the field. On 24 January 2008, a full Farm-Out Agreement and the JOA were entered into, superseding the previous Letter Agreement. The JOA is mistakenly dated 24 January 2007.

The results from the drilling of well 12/21c-6 were encouraging. Ithaca and NSE submitted a field development plan to DECC for approval. It proposed conversion of well 12/21c-6 to a production well (which subsequently became known as Well J01). It also recorded that the facilities for production from this well would be designed to allow for future expansion; and that space would be provided on the proposed Jacky wellhead platform for a further production well and a water injection well. In addition, to allow for a potential future water injection well, it was proposed to install a water injection pipeline from Beatrice Alpha, a platform in the Beatrice Field, to Jacky. The idea of drilling a water injection well and a second production well was something which Dr Morel of Ithaca had recommended in January 2008 and was a serious prospect, to which specific consideration had been given by Ithaca. It was not, however, part of a programme to which the participants committed themselves in the FDP. The FDP set out the proposed capital expenditure as being $119 million.

Ministerial approval was given on 10 November 2008. On the same day Ithaca and NSE entered into the Amended and Restated JOA.

The boundaries of the Jacky Field were set by DECC in February 2009, thus establishing the FDA. Once the FDP had been approved, and the FDA established, Ithaca could not only complete Well J01 (which was proposed in the FDP), but were also entitled to drill any further development wells within the Jacky Field upon the obtaining of a permit to drill, irrespective of whether the location of a further production well was or was not the same as that indicated in the FDP.

Towards the end of 2008, Dyas took a 22.725% interest in the Jacky Field. Dyas’s interest was subsequently increased to 42.5% in July 2009. Pursuant to Novation and Amendment Agreements granting these interests and dated, respectively, 17 December 2008 and 29 July 2009, Dyas became a party to the JOA, together with Ithaca and NSE.

In January 2009, the Jacky wellhead platform was installed. First oil began to flow on 6 April 2009.

Following a drop in pressure, the co-venture partners agreed to drill a second well, Well J02, as a water injection well to support production from Well J01. The well proposal document proposed the drilling of the water injection well to support production from Well J01, but recognised that the well was positioned “to act as support for a potential future second production well which would increase reserves from the Jacky Field by a further 2.0 mm bbls of oil”. In late October 2009, Well J02 was drilled and successfully completed as a water injection well.

The drilling of Well J02 established that the reservoir at that location was in hydraulic communication with Well J01; the data was also interpreted as showing that the Oil Water Contact depth (“OWC”) was the same as that found at the Britoil Well.

In August 2010, consideration was given by Ithaca to drilling a second production well. On 3 September 2010 there was an internal Ithaca meeting attended by Mr McKendrick (CEO), Mr Forbes (CFO), Mr Woods (Chief Development Officer), Mr Kyle (Commercial Manager), Mr Muir (Chief Technical Officer), Dr Morel (Reserves manager) and Mr Scott (Reservoir engineer). At this meeting, Mr Scott made a slide presentation, including an evaluation of three possible drilling locations for what was to be Well J03.

On 21 September 2010, Mr Kyle sent an email to NSE and Dyas, inviting them to attend a meeting of the Operating Committee on 13 October 2010. The email promised that an agenda and draft proposed budget would be circulated before the meeting but indicated it would include “…the Technical Work in support of the Second Jacky Producer…”.

On 29 September 2010, Mr Kyle sent a number of documents to NSE and Dyas as attachments to an email. The subject field of Mr Kyle’s email was “Drilling Proposal on Jacky – Second Producer”.

The attachments include a document, marked Appendix III, headed “Ithaca Energy 2nd Jacky Producer”. This document showed proposed capital expenditure of £19.8 million, of which £18.5m was well cost and £1.3 million the cost of tie back to the platform. It gave an estimated net present value (NPV) of the net income (i.e. income above expenditure) to be derived from the proposed well on six different hypotheses. The six alternative hypotheses were more fully explained in a document also attached to the email entitled “Outline Summary of 2011 Jacky Drilling Campaign”. This document explained that:

“The planned well is a second producer and will target the structural high northeast of well 12/21-2 [Britoil Well]. The producer is planned to accelerate oil recovery and add incremental reserves.”

The same document referred to two principal subsurface uncertainties. The first was the A-Sand reservoir quality around the target location; the second was the depth at which the top of the reservoir lay at the mapped structural high. These merit further explanation.

The reservoir quality uncertainty was that quality was controlled by the width of higher permeability A-Sand channel which was intersected by the Britoil Well and Well J01. Two alternatives were canvassed, a more optimistic “Wide Channel” and a more pessimistic “Narrow Channel”. The Narrow Channel was described as the base case.

The second uncertainty was based on the OWC being identified as being at 6913 ft TVDSS (True Vertical Depth Sub Sea). The OWC effectively determines the depth of the floor of the oil reservoir at the proposed location. The second uncertainty was as to the depth of the roof of the reservoir. It was therefore obviously one which could have a significant impact on the quantity of oil which could support economic exploitation. The estimates of the depth of the roof of the oil bearing A-Sands were derived from seismic tests which had not been undertaken at the location of Well J03 and were in any event, as was subsequently explained to me in the evidence, subject to a margin of error of about 50ft either way. The geological mapping of the subsurface was therefore subject to the uncertainty inherent in the seismic data.

This was identified in the Outline Summary of 2011 Jacky Drilling Campaign attached to Mr Kyle’s email of 29 September 2010 as being illustrated by the fact that Well J02 had encountered the A-Sand 60ft deeper thaN the prognosis provided by the mapping based on seismic data. The effect of such uncertainty on the success of the well was reflected in a passage which stated: “If the structure is 50ft deeper than the base case, then the [quantity of oil] within the secondary closure would be less than half. If the structure is 50ft shallower, then the [quantity of oil] would be about 60% higher”. These three possible top structure depths were described as a Low, Medium and High case and were applied to the Narrow Channel and Wide Channel alternatives to give six alternative prognoses of recoverable oil. For budgetary purposes the base case, described as “most likely” was the Mid depth structure applied to the Narrow Channel model. This gave a projected incremental oil recovery from the well over 5 years of 1.1 million barrels, which would make a profit of £26 million discounted to NPV. The best case (Wide Channel, High depth) would produce an NPV profit of £88 million. The worst case (Narrow Channel, Low depth) would produce a net loss of £11million. The other four alternatives predicted net profit to varying degrees.

The costs of £19.3m were broken down in Appendix I as being £11.6m for the drilling operation, £6.9m for completion of the well as a producer and £1.3m as the tie back costs.

On 30 September 2010, Ithaca, as Operator, issued a proposed Work Programme and Budget for the Jacky Field for 2011. That document identified that “The 2011 Capital budget includes a second Jacky production well” and included in the “Firm Budget” for the first quarter of 2011 capital expenditure (“Capex”) of £19.8m for “J03 2nd Jacky producer”.

On 5 October 2010, Mr Powers, the Chief Operating Officer of NSE, sent an email expressing a number of concerns. Under the heading “Location Risk” he said:

“NSE acknowledges and agrees with the Operator’s position that reservoir quality and top reservoir depth are uncertain at the present location. We note, however the absence of discussion or reference to nearby fault considerations. Although 6 outcomes are reviewed no individual case contemplates total failure and no “Chance of Success” for the base case is suggested.”

The reference to “nearby fault considerations” was explored more fully in the subsequent communications and in the evidence before me. It is worth observing, however, that in this passage NSE recognised that the forecasting by Ithaca (about which they were concerned), envisaged going into production to recover oil in each of the six alternative predicted outcomes, even the most pessimistic being one in which the projected net loss was less than the projected total expenditure. This was what was meant by the observation that no individual case contemplated total failure.

On 13 October 2010, a meeting of the Operating Committee took place to consider the proposed Work Programme and Budget. Those attending for Ithaca included Mr Kyle, Mr Gould (a geologist) and Mr Scott. Attending for NSE were Mr. Anderson (CEO), Mr Powers (COO) and Mr Austin together with an adviser, Mr Cosgrove. Representatives of Dyas also attended. A number of slide presentations were made by Ithaca at this meeting, with copies being sent to NSE the following day. The principal relevant presentations were:

The first two identified an important factor which allowed much room for debate about the subsurface structure of the field. This was that the production from J01 had exceeded that which could be explained by the existing model. The water cut data and the pressure data from Well J01 could not be reconciled with an OWC in that part of the field of 6913 ft. This was perplexing because 6913 ft was the OWC measured at Well J02; and Well J02 was regarded as in hydraulic communication with Well J01 because as an injector it was effectively and efficiently sweeping oil for extraction from Well J01. Well J01 and Well J02 could therefore be expected to be accessing a single accumulation of oil with a floor of 6913 ft. Various methods of manipulating the top structure map had been unable to produce a model with a satisfactory match to the data from production at Well J01.

Accordingly the static modelling put forward by Mr Gould in the second of the three presentations posited a different OWC in the part of the field in which Well J01 was located. Mr Gould’s “Current Top Structure Map” identified the scissor fault which formed an effective oil seal running NE/SW through the greater part of the field but not as far as its southerly end. Well J01 was in the south eastern portion and Well J02 in the south western. These could feasibly be in communication to the south of the point to which the scissor fault extended. The Britoil well was to the north of Well J02, on the western side of the field and lying west of the scissor fault. The location of Well J03 was further to the north of the Britoil Well, again on the western side of the scissor fault. The map appeared to identify two separate closed structures in the field. One to the northwest, with an OWC of 6913ft, included the Britoil Well and area in which Well J03 was to be drilled; this was sealed on its eastern side by the scissor fault. The second ran with an OWC of 6913ft from the tip of the scissor fault westward round Well J02 and eastward again round Well J01. At the north eastern end it was closed by the OWC which met the scissor fault closing it on its north west. Such a model was regarded as best fitting the data from Well J01. But the difficulty for the geologists was that it posited that the OWC at and to the north of Well J01 was not 6913ft but 7200 ft, despite the fact that Wells J02 and J01 were placed in a single closure and the OWC at Well J02 was measured at 6913ft. The problem for the geologists was to explain how such a disparity in OWC could exist when it was accepted that Well J02 was in hydraulic communication with Well J01; and if it could not exist, how was the pressure and watercut data from Well J01 to be explained?

Mr Gould’s hypothesis was that the OWC had originally been deeper than 6913ft across the whole field, but there had been a leak of oil from the west to the east at some point in the distant history of the geological formation of the field, leading to a shallower OWC on the western side. The difference in the OWC at Well J02 and that at Well J01 was to be explained by a boundary fault between them which had been broken down by the water injection at Well J02 once it became operational.

In the last of the three presentations, Mr Scott’s slides identified first of all that there was a poor history match between the data from Well J01 and the previous static model which assumed an OWC of 6913 ft throughout both sides of the field. He advanced two alternative dynamic models. Both assumed a “perched OWC scenario”, that is a deeper OWC on the eastern side than the 6913ft measured at both Well J02 and the Britoil Well. Model 1 assumed a narrow channel, an OWC on the eastern side of 7,100 ft and the roof of the reservoir lifted by 50ft above what was shown in the seismic data in what was referred to as “the saddle area”. The saddle area was the dip in the projected reservoir roof in the area around the south of the tip of the scissor fault. Its precise configuration determined whether the north western portion in which the Britoil and J03 Wells were located was part of a single structure in hydraulic communication with the part of the field accessed by Well J01 and Well J02; or whether on the other hand the two were separated by the scissor fault. In simple terms, raising the saddle by 50 ft posited a single structure which included all the wells. Mr Scott’s Model 2 posited an OWC on the eastern side of 7,200ft, a Wide Channel and the saddle area as mapped on the basis of the seismic data. His presentation went on to show that the data history match for both Models 1 and 2 was much better than that for the previous static model. Before me there was a dispute, to which I shall have to return below, as to whether leaving the top of the saddle where indicated by the seismic data, as Model 2 did, meant that the tip of the scissor fault was such as to create a seal separating the field into two separate structural closures.

The slide presentation repeated the key subsurface uncertainties as being reservoir quality (narrow or wide channel) and top depth structure, to which Mr Scott attributed an uncertainty of plus or minus 50ft.

One slide identified three potential locations for Well J03. They were mapped on a representation of Model 1, i.e. the model which assumed the top of the saddle being raised by 50ft and consequently a single structure with a single accumulation across the whole field.

The upshot of the meeting, so far as Well J03 is concerned, is recorded in minutes circulated for approval at the beginning of November. NSE sought to have the well treated as a contingent budget item but this was not supported. NSE voiced its objections to the proposal and explained its concerns. Dyas requested that Ithaca consider NSE’s points and prepare a final justification and an Authorisation for Expenditure (“AFE”) for the partners to consider.

There is a dispute of fact as to what was said at the meeting on 13 October 2010 in two respects. Mr Anderson’s recollection was that Mr Scott said that the chance of economic success of J03 was 50/50; this was denied by Mr Scott. Secondly Mr Anderson’s and Mr Power’s evidence was that Mr Scott was asked whether J03 was in a separate structure, and replied that it was in a separate structure.

As to the first:

As to the second:

On this issue, I find that Mr Scott did say that the target location was in a separate structure, in the context of a discussion in which the concern being addressed was whether production from Well J03 would deplete production from Well J01. That is supported by the contemporaneous notes Mr Anderson made at the meeting. Of the two models presented by Mr Scott, it was Model 2, not Model 1 which involved the mid case as to the reservoir surface depth; Model 1 raised it by 50ft. I found Mr Scott’s attempts in cross examination to portray his Model 2 as one positing a single accumulation unconvincing. Mr Scott conceded that from mid-2009 onwards, he had presented subsurface mapping indicating that the Jacky Field contained two separate structural closures. He accepted this in relation to a power point presentation he gave to DECC on 2 June 2009, a presentation he sent to Mr Woods attached to an email of 2 July 2009 and the Well Proposal for J02 prepared in July 2009. His explanation of what was presented at the 13 October meeting is that it was a part of Model 2 that there was communication over the scissor fault where there is sand to sand contact. Mr Scott went on to argue that there was in fact a single accumulation of oil as part of Model 2, due to the throw of the fault being smaller than the estimated depth of the reservoir. Such a possibility was not supported by the expert evidence. As Mr Rhys Davies explained, a different OWC in the east and west (which is the perched water hypothesis for Model 2) requires a seal between the two halves. The existence of a seal between the halves separating Well J02 and Well J01 was potentially explicable by Mr Gould’s theory of a seal which was broken down by Well J02 coming into operation. But if the scissor fault as shown in Mr Gould’s structural interpretation did allow oil to oil communication across the fault (as Mr Scott now says was envisaged by Model 2) it would have been impossible for there to be two OWCs because over the millennia oil would have pressed westwards from the east, until such time as the pressures (and hence the depth of the respective oil columns) either side of the fault had equalised. It is also notable that it was Mr Scott’s drafting of the document attached to the 29 September email I have quoted above which refers to the J03 area as a secondary closure. Mr Scott also explained that he would have seen and approved the drafting in section 4.1.3 of the subsequent J03 Well Proposal Document which stated: “The target location is in a second structural closure located in the northern part of the Jacky Field” (see below).

On 3 November 2010 Ithaca sent NSE and Dyas two documents as attachments to an email, with hard copies sent under cover of a letter the following day. One was a 49 page Well Proposal for J03 (“The Well Proposal”). The other was an AFE.

The AFE was entitled “Drill and Complete Jacky Production Well J03”. It had been signed as approved by Ithaca and approval was being sought from the other two participants. It gave detailed costings, which totalled approximately £23.6 million. These comprised about £12 million for the well drilling, £6.9m for completion of the well as a producer, £1.3 million for tie back to platform, £2.9m for contingencies and £550,000 for overheads.

The Well Proposal contained the following:

If it matters (which for the reasons I discuss below, I do not think it does), my conclusion is that the Well Proposal did not treat Well J03 as a well which was proposed to be drilled into a separate structural closure from that in which Wells J01 and J02 were drilled. It put forward two models, one of which involved Well J03 being in a separate structural closure and one of which did not. It was neutral as to which was more likely.

NSE responded to the Well Proposal and AFE in a letter of 10 November 2010 stating its reasons for opposing the drilling of the proposed well. The letter said “Under no circumstances will NSE participate in the currently proposed Jacky J03 well.” Two aspects of that letter are potentially significant. It provided that “NSE is not convinced that the location of the well targets a separate accumulation to the main Jacky reservoir”, suggesting that NSE were also ambivalent as to whether Well J03 was in a separate structural closure, just as Ithaca appeared to be from the neutral treatment of Models 1 and 2 in the Well Proposal. Secondly, the letter concludes by Mr Anderson saying that he believed all parties would be better served by “aligning themselves on an agreed workscope involving further appraisal of” the Jacky Field, rather than pursuing Ithaca’s proposal which was “a marginal well”. Implicit in this exhortation was the view that the well proposed by Ithaca was not for the purposes of appraisal.

Dyas was hesitant about the project. Over the following weeks, Dyas’s technical team raised a number of queries in relation to the technical basis of Ithaca’s proposal, resulting in further communications from Ithaca. At a meeting on 17 November 2010, Mr Hoonhorst of Dyas informed Mr McKendrick of Ithaca that Dyas was “still not convinced and will start to look at risking of this almost on an exploration basis.”

On 19 November 2010, Mr Hoonhorst of Dyas indicated to Ithaca that Dyas’s technical team would be recommending to Dyas’s management that they proceed with drilling a new well, subject to certain caveats, one of which was “Confirmation that the dry hole costs are under GBP 13 min (100%)”. This appeared to be recognition by Dyas that there was at least a possibility of not finding any or any sufficient oil to justify the further expenditure of completing the well for going into production.

Ultimately, on 1 December 2010 an email sent by Dyas’s Managing Director confirmed that its Executive Board of Directors had given approval to “drill and complete” Well J03. Dyas signed the 2011 Work programme and Budget and the AFE on the same day.

On the same day, 1 December 2010, Ithaca wrote notifying NSE that the Work Programme and Budget and AFE had now been formally approved by Ithaca and Dyas. On 6 December 2010, NSE wrote claiming to exercise its right pursuant to clause 14.9 of the JOA to “non consent” to the drilling of Well J03.

The drilling of Well J03 was carried out by Senergy, an international energy services company. Prior to doing so, it compiled a drilling programme which contained a number of references to Well J03 as a production or development well. The programme states the well “Objectives” included the work which would be required to complete it as a producer.

As I have explained, it was common ground between the parties and their experts that there are generally four stages in the exploitation of an oil concession, namely exploration, appraisal, development and production; but that there may be cases when activity which could properly be described as appraisal is undertaken in relation to part of a concession after there had been development or production activity in the concession, or part of it.

This is reflected in the structure and language of the JOA. Clause 10 provides that the Operator may submit an annual exploration Work Programme and Budget (“WPB”) and AFE for the following year. Clause 11 provides that in the event of a discovery the Operator may (and shall if requested by a party) submit an annual appraisal WPB and AFE for the following year. Clause 12 provides that in the event of a discovery the Operator shall submit a development WPB; in this case the WPB is to cover the current year and the following three years. A discovery may therefore be followed by appraisal or it may lead directly to development. A development WPB, once approved, automatically triggers an application to DECC for approval of an FDP under the Licence (Clause 12.1.4). Clause 13 provides that if the field is to go into production the Operator must submit a production WPB for the following year 40 days prior to commencement of production and annually by 30 September each following year. Under clauses 12 (development) and 13 (production) there is also required to be approved an AFE for any expenditure over £500,000 (other than annual operating costs). There is nothing in these clauses to restrict the Operator from submitting an appraisal WPB in any year in addition to a production WPB.

The JOA provides for decisions to be taken by the Operating Committee by voting. Clause 8.8.2 imposes two conditions for the validity of such decisions (referred to in the JOA as the “passmark”):

The general principle pervading the JOA, consistent with its joint venture nature, is that participants are bound by the decisions of the Operating Committee and bound to share in the costs and expenditure of such activities, as well as sharing in any of the benefits which may result. By way of exception to this general approach, the JOA also provides for two sets of limited and defined circumstances in which a participant who is outvoted may depart from the default position of joint benefit and burden. The first is where a participant wishes to undertake an activity which the Operating Committee has declined to undertake. In the defined circumstances, it may undertake that activity for its own sole risk and account. This is referred to in the JOA as a Sole Risk Project. The second exception arises where a participant wishes not to participate in an activity which the Operating Committee has decided to undertake. In the defined circumstances the participant may opt out of the obligation to contribute to the costs of the activity (and thereby forego the entitlement to share in any benefits which might result, subject to an ability to buy its way back into a share of the benefits by subsequent election to pay a multiple of what its cost obligation would have been). This is referred to in the JOA as Non Consent. The two exceptions are in some ways two sides of the same coin and are dealt with together in Clause 14 of the JOA. This case is concerned with Non Consent. But because the circumstances in which Non Consent is permissible are defined in the JOA by reference to the clauses concerned with Sole Risk Projects, it is convenient to start with a summary of the provisions concerned with Sole Risk activity.

Clause 14.1 identifies four categories of activity which are potentially capable of being undertaken as Sole Risk activity, subject to the other provisions of the clause. They comprise seismic, testing, drilling and development activity, each separately defined but each falling within the definition of “Sole Risk Project”. We are concerned with the third, namely “sole risk drilling, as more specifically set out in Clause 14.2.2(ii) (“Sole Risk Drilling”)”.

There are two constraints on when Sole Risk Drilling may arise. The first is contained in Clause 14.2.2 (ii) which defines the nature of the drilling activity which is capable of being Sole Risk Drilling activity. The second constraint is provided by Clause 14.3, to which clause 14.2.2(ii) is expressed to be subject. This defines the procedural circumstances which must exist before drilling falling within clause 14.2.2 (ii) can be a Sole Risk activity.

Clause 14.2.2 (ii) is confined to four types of well drilling:

There are two contrasts between subparagraphs (a) and (b) on the one hand and subparagraph (d) on the other. First, the former refer to a geological compartment where petroleum of potential commercial significance has been discovered, whereas the latter refers to a geological compartment where some petroleum has been discovered, whether of potential commercial significance or not. Secondly, the former provisions are concerned with exploration well activity, the latter with appraisal well activity.

The structure and language of these subparagraphs envisage that one purpose of an appraisal well may be to determine whether a discovery of oil within a geological compartment which was not identified as being of potential commercial significance is indeed of potential commercial significance. But they do not so confine it. In particular sub paragraph (d) is wide enough to contemplate an appraisal well being drilled into the same geological compartment in which there has been a discovery which is already regarded as of potential commercial significance. It is wide enough for the appraisal, contemplated as the purpose of an appraisal well, to be more than simply whether the discovery is “of potential commercial significance”. In other words, there is nothing in the language of these provisions which dictates that a well can only be an appraisal well if drilled into a separate geological compartment from one which is already in production.

This puts into context the debate in the evidence before me as to whether Well J03 was to be drilled into a separate geological compartment from that which was being serviced by Wells J01 and J02, or perhaps more accurately was perceived as being so drilled by the parties at the time. It will be remembered that in order to be an appraisal well within the meaning of clause 14.2.2(ii)(d), Well J03 would have to be being drilled into the interpreted closure of any geological structure or stratigraphic trap on which a well has been drilled in which Petroleum has been found to be present.” But this requirement is fulfilled whether there were one or two geological compartments. Well J03 was to be drilled into the same geological compartment as the Britoil Well, whether or not that was in a separate geological compartment from Well J01 and Well J02.

The issue whether the area targeted by Well J03 was, or was perceived at the time to be, a separate geological compartment from the area in production from Well J01 was addressed extensively in the evidence adduced by NSE. This was concerned to show that it was in a separate geological compartment. Ithaca responded to this evidence, and the dispute raised a number of sub issues which were canvassed in the oral evidence of the factual and expert witnesses before me. I had some difficulty in understanding how this issue affected the outcome of the proceedings. In its oral opening submissions Mr Graham QC on behalf of NSE said that the issue went to an argument being advanced by Ithaca that Well J03 could not be an appraisal well because it was in the same geological compartment as Well J01; and that since Well J01 had originally been drilled as an appraisal well and the whole field had been thereby appraised and the subject of the FDP, it followed that Well J03 could not be an appraisal well. In fact, Ithaca did not advance such an argument, and Mr McCaughran QC’s submissions on its behalf made clear that it did not matter for the purposes of Ithaca’s case whether Well J03 was in the same or a separate geological compartment from Wells J01 and J02.

As the argument developed at trial, the question whether Well J03 was perceived to be within a separate geological compartment remained irrelevant on Ithaca’s case, but became relevant to a new way in which Mr Graham QC put NSE’s case in which the criterion for whether a well was an appraisal well was linked to whether it was targeting oil comprising proved reserves or contingent resources. For reasons I will I explain, I reject that as a valid or relevant approach. I do not therefore find it necessary to decide whether Well J03 was a well to be drilled into a separate “geological structure or stratigraphic trap” as that accessed by Wells J01 and J02. As I have found above, Mr Scott’s opinion expressed at the 13 October 2010 meeting was that it was, but the subsequent Well Proposal was neutral on the question.

Non Consent is governed by Clause 14.9 of the JOA which provides as follows:

“If the Operating Committee shall have approved the drilling of any well falling within the description in Clause 14.2.2(ii)(a), (b) or (d) (disregarding any reference therein to “Sole Risk Drilling”) the following procedure shall apply:

(i)

the Operator shall, following such Operating Committee approval, give notice to all Parties of approval of the operation in question;

(ii)

within fourteen (14) days of receipt of such notice, any Party which voted against the drilling of such well may give notice to the Operator and all the other Parties stating that it elects not to participate in the said operations;

(iii)

each Party that gives notice pursuant to Clause 14.9(ii) shall be a “Non-Consenting Party” and each other Party shall be a “Consenting Party”;

(iv)

if there are Non-Consenting Parties having an aggregate Participating Interest of less than thirty five percent (35%) then, notwithstanding any other provision of this Agreement, the Consenting Parties shall be entitled (and, as between themselves, shall be obliged) to carry out the drilling of the well as if it were Sole Risk Drilling pursuant to Clause 14.2.2(ii); and

(v)

the provisions of Clause 14 in relation to Sole Risk Drilling (other than Clause 14.3 and the proviso to Clause 14.2.2(ii)(b)) shall apply mutatis mutandis to such operations;

(a)

such operation shall be deemed to be Sole Risk Drilling;

(b)

the Non-Consenting Parties shall be deemed to be Non-Sole Risk Parties and the Consenting Parties shall be deemed to be Sole Risk Parties; and

(c)

no further notice shall be required in relation thereto pursuant to Clause 14.2”

Some industry literature containing definitions of appraisal and development wells was drawn to my attention. A Glossary on the website of Oil and Gas UK contains the following:

“Appraisal Well

A well drilled as part of an appraisal drilling programme which is carried out to determine the physical extent, reserves and likely production of a field”

Development Well

A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive; a well drilled in a proven field for the purpose of completing the desired spacing pattern of production.”

Glossaries promulgated by ConocoPhillips and Shell use the same language.

The essential distinction drawn between the purpose of each type of well in these definitions is that an appraisal well is concerned with a search for information, whereas a development well is concerned with the extraction of oil. A similar distinction appears in the definition of a development well at clause 17(4) of the Licence, which is in the following terms:

“Development Well” means a Well which the Licensee uses or intends to use in connection with the getting of Petroleum in the Licensed Area, other than a Well which for the time being he uses or intends to use only for searching for Petroleum.”

Against this background, and the industry practice I have identified earlier, the parties made rival submissions as to the criteria to be applied in deciding whether something was an appraisal well for the purposes of Clause 14.2.2(ii)(d).

Mr McCaughran QC on behalf of Ithaca submitted that:

Mr Graham QC on behalf of NSE submitted that:

Three points may be cleared out of the way.

First, I accept, as both parties submitted, that it is necessary to apply a test which depends upon the purpose for which the well is drilled. I also agree that what needs to be identified is the primary or predominant purpose. Although purpose involves a subjective state of mind, the primary purpose for which the well was drilled is to be ascertained objectively from what was communicated by the participants who made the decision, namely Ithaca and Dyas. That might have raised a potential difficulty because it is possible to have different purposes driving the same project in the minds of different participants. But that difficulty does not arise in this case, where I am satisfied that Dyas adopted the purpose which was manifest from Ithaca’s proposal and subsequent communications.

I therefore accept the Claimant’s submission that the status of the well is to be determined by the purpose of Ithaca (and Dyas) in drilling it. That is not to say that designation or labelling of the well by Ithaca is conclusive. If Ithaca’s purpose, objectively assessed, were to drill what is properly characterised as an appraisal well, it would not be any less so because Ithaca described or designated the well as a production well. Labelling by the Operating Committee at the time is not determinative. But contemporaneous descriptions by the parties and interested observers are not wholly irrelevant. Unless being used as a device to buttress future arguments (which I do not consider happened in this case), the language used to describe the well by Ithaca, Dyas, NSE and others is evidence from which one can draw inferences as to how they intended and understood its purpose. The individuals concerned were experienced in this industry and can be taken to have understood the import of describing activity as “appraisal” or “production”.

Secondly, I reject Mr Graham QC’s second submission that the question is to be determined by reference to whether what is being targeted are “contingent resources” or “reserves”. This requires an explanation of the language used for accounting purposes in the oil industry which is to some extent adopted or adapted in the language used in other contexts.

Mr O’Driscoll set out a description of what “reserves” are at paragraph 2.118 of his main report:

“Reserves are quantities of petroleum anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under defined conditions.”

Mr O’Driscoll went on to explain that reserves must be “discovered, recoverable, commercial and remaining”. Where there is discovered and remaining oil which is recoverable but is not (yet) thought to be commercial it will not fulfil this description. Such oil will be categorised instead as “contingent resources”.

Reserves themselves are broken down into 3 categories (proved, probable and possible) and 3 combinations (1P, 2P and 3P). The first category of reserves is “proved reserves”. The PRMS definition of Proved Reserves is:

“those quantities of petroleum, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under defined economic conditions, operating methods, and government regulations. If deterministic methods are used, the term reasonable certainty is intended to express a high degree of confidence that the quantities can be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate.”

Proved reserves are the first category of reserves and also the first combination, since the first reserves combination (1P) means proved reserves, on their own. It is sometimes covered by the expression “P90 volume oil” i.e. the volume of oil of which there is a 90% probability of recovery from a target location. But it is only P90 volumes of oil which are commercially recoverable that qualify as “proved reserves”.

The second category of reserves is “probable” reserves. These are quantities of oil, additional to proved reserves, where there should be at least a 50% probability that the quantities actually recovered (on equivalent assumptions), and with positive economics, will equal or exceed the estimate. The second reserves combination is 2P reserves and this means “Proved + Probable” Reserves.

The third category of reserves is “possible” reserves. These are quantities of oil, additional to proved and probable reserves, where there should be at least a 10% probability that the quantities actually recovered (on equivalent assumptions), and with positive economics, will equal or exceed the estimate. The third reserves combination is 3P reserves and this means “Proved + Probable + Possible” Reserves.

The argument advanced on behalf of NSE by Mr Graham QC is that no well could properly be described as a production well if it were targeting contingent resources; and that it would have to be targeting proved reserves before it could properly be so described; otherwise it would properly be characterised as an appraisal well.

As a criterion for determining whether a well is an appraisal well, this is inconsistent with his first submission, namely whether its primary purpose is to evaluate the commercial viability of investing the funds necessary to carry out a particular project for the recovery of oil from a target location. It would produce the curious and anomalous result of designating as an appraisal well something which was always intended to, and did, go into production. An example which I put to Mr Graham QC in the course of argument is illustrative. If there were a P90 volume of oil at the target area worth £15m and an 80% probability of a great deal more, the target would be categorised as contingent resources assuming a well costing £15m to drill and £5m more to complete and tie back; the P90 volume would be less than the £20m expenditure envisaged as necessary to extract it. But an Operator might well say that it would drill a well there and complete it come what may, because if there were an 80% probability of finding very large quantities of oil in addition to the P90 volume, the prospects of profitable exploitation far outweighed the small risk of finding less than £20m worth of oil; and even if all that were found were the P90 volume worth £15m, spending the additional £5m to complete and tie back the well would be economically justified by recovery of £15m worth of oil to recoup the costs of drilling the well. Such a well would not be an appraisal well if one applied Mr Graham QC’s first test, nor would it contemplate any appraisal at all in any commercial sense. Yet on his second test it would be targeting “contingent resources”.

In truth this way of putting the case only emerged very late in the day. It was not pleaded and was not part of NSE’s written or oral opening at trial. It emerged for the first time in the written closing submissions, in reliance on the evidence of Mr Rhys-Davies which only clearly made this point at the conclusion of his evidence in answers to the Court. It was put forward by way of assertion without any support in any literature, really as being no more than Mr Rhys-Davies’ view. It was not a view shared by Mr O’Driscoll. The latter explained that he had experience of projects which were sanctioned for production where the P90 case was not commercially profitable, but the P50 and above case meant that the volume of oil which was regarded as more likely than not to be recovered justified the expenditure. It all depended on the appetite for risk of particular participants, and there were no hard and fast rules about having to undertake appraisal activity if the P90 case was negative. What mattered was the intention of the parties given their particular appetite for risk. In cross examination, Mr O’Driscoll explained that, in his experience, there was a difference in approach between the larger oil companies, which tend to pursue a risk-averse approach, and the smaller companies (who represent the larger part of the number of companies producing, though not the larger part of the barrels produced), which “generally speaking have a larger appetite for risk and are prepared to invest if the P90 case does not look like it is economic”. This seemed to me logical and compelling. I reject any suggestion that practitioners in this industry would necessarily have treated a well targeting “contingent resources” as an appraisal well.

Mr McCaughran QC objected to the argument being allowed to be advanced at all, on the grounds that Ithaca had not had a proper opportunity to address it in their expert evidence without it having been identified before Mr O’Driscoll gave evidence. If necessary I would have acceded to that submission; but having heard the argument I reject it on its merits.

Thirdly, I reject Mr McCaughran QC’s secondary argument that, even if a well is properly categorised as an appraisal well by reference to its purpose, it cannot be an appraisal well within the meaning of Clause 14.2.2(ii)(d) under the JOA after the development phase has been reached. The argument ran as follows:

I do not find this analysis persuasive. True it is that, where the appraisal WPB in respect of an interpreted closure has been abandoned or completed, clause 14.3.2(ii) envisages that a Sole Risk Drilling project can only be proposed if a development WPB has not been proposed in respect of that closure. But the argument based on Clause 14.3.2 assumes that Sole Risk drilling of an appraisal well after development is precluded by sub paragraph (i) as well as (ii). This is not so. Clause 14.3.2 provides:

“No Sole Risk Drilling under Clause 14.2.2(ii)(d) may be proposed unless:-

(i)

the Operating Committee has voted against, or failed to vote in favour of an appraisal Work programme proposal in respect of the interpreted closure of any geological structure or stratigraphic trap on which a well has been drilled in which Petroleum has been found to be present ….; or

(ii)

the Operating Committee has abandoned or completed its appraisal Work Programme of the interpreted closure of any geological structure or stratigraphic trap on which a well has been drilled in which Petroleum has been found to be present and a development Work Programme has not been proposed to the Operating Committee and no Party has given notice under Clause 14.5.1 that it intends to prepare such a development Work Programme.”

Given that it is accepted that the parties may carry on appraisal activity as an incremental project after the development phase has commenced in the field, I do not see why such appraisal activity, including an appraisal well, can not be the subject matter of an appraisal WPB, alongside a development or production WPB for the rest of the field activity, so as to trigger clause 14.3.2 (i) if it is voted down by the Operating Committee.

There is a more fundamental obstacle to this aspect of Ithaca’s argument. Clause 14.9(v) specifically disapplies clause 14.3 in the context of non consented drilling. Further, the opening words of clause 14.9 specifically provide that in assessing whether a well falls within the description of one of the relevant sub-clauses “any reference [in clause 14.2.2(ii)] to Sole Risk Drilling” shall be disregarded. The purpose of this can only have been to avoid the result that in the context of clause 14.9 a drilling proposal had to satisfy the wider requirements of a Sole Risk Drilling proposal set out in clause 14.3.

One can understand a sound rationale for that approach. Clause 14.2.2 constrains the type of activity which can be Sole Risk drilling, which is carried over into the non consent criteria in 14.9; whereas clause 14.3 imposes a conditional limitation on when a permitted Sole Risk activity can be undertaken as such. Without a clause such as clause 14.3, there would always be a risk that a Sole Risk Drilling proposal (as distinct from a non consented drilling proposal) might conflict with a development Work Programme. But in the context of a non consented drilling proposal under clause 14.9, there is no likelihood of such a conflict arising. The non consented drilling project will be one which a majority of the Operating Committee has already voted for. There should therefore be no difficulty in the Operating Committee ensuring that the non consented drilling project does not conflict with any other drilling project for which it is responsible. The essential difference between the two cases is that with non consented drilling under clause 14.9, the Operating Committee is going to be in control both of that drilling project and of any other drilling project forming part of a development or production work programme and can ensure that conflict between them is avoided; whereas with a Sole Risk Drilling project that would not be the position.

As to clause 14.4, it applies to non consented drilling “mutatis mutandis”. It takes no significant manipulation to apply it in the development phase of a field to the subsequent exploitation of a successful non consented appraisal well in part of the field. In such circumstances it can treat the triggering event in Clause 14.4.1 as a development or production work programme in relation to the discovery made by the drilling of the appraisal well; and in Clause 14.4.2 as the grant of authorisation under clause 13(1)(b) of the Licence for that production. It is clear that authorisations may be required under clause 13 of the Licence notwithstanding that there has been previous approval of an FDP; indeed the approval given by DECC to the FDP on 10 November 2008 specifically required subsequent applications to be made under clause 13(1)(b) of the Licence. Section 13 authorisations are therefore envisaged after the development phase.

Moreover given the agreement between the experts that, as matter of industry practice, parties can undertake appraisal activity after having reached the development phase, it would be surprising if these parties drafted their agreement to define an appraisal well as an activity of which a party was permitted to opt out, but to have precluded such opt out after the development phase, without saying so expressly in the opt out provision.

With these arguments out of the way, there is little difference between Mr McCaughran QC’s formulation of the necessary primary purpose (to gather information in order to inform a decision as to whether or not to proceed to a development project) and that of Mr Graham QC (to evaluate the commercial viability of investing the funds necessary to carry out a particular project for the recovery of oil from a target location). Well J03 would be drilled as an appraisal well if its primary purpose, as seen by the Operating Committee, was to gather information and analyse it in order to inform a subsequent decision as to whether to make a further investment of funds in order to complete it as a production well. This would take it outside the definition of Development Well in the Licence as being one which the Operating Committee “for the time being intends to use only for searching for Petroleum”. On the other hand Well J03 would be drilled as a development or production well if its primary purpose was to be used for the extraction of oil.

Applying this test, there are a number of features of the evidence which point towards Well J03 being properly characterised as a development well or production well, not an appraisal well.

None of the discussions or proposals of the parties in relation to the Well envisaged a two-stage process of drilling the well in the first instance in order to collect and analyse data to remap the sub sea geology; then pausing to analyse the data and using it as a basis to inform a separate decision as to whether to proceed to a second stage of putting the well into production. On the contrary what all the discussions and proposals envisaged was a single operation of completing the well as a production well. There was no intended pause between the work of drilling the well to the A Sands and the work of completing it as a production well. The Well Proposal is a good illustration of this. It not merely described the Well Objectives as being “to drill a second producer”; with one of the key operational requirements to achieve this objective being “Complete the well as a producer” (Section 1.1). Its whole thrust was of a single stage exercise of drilling a well which included the necessary production elements. It did not suggest any separate or first stage exercise of the collection and analysis of data, nor a pause for the purposes of such analysis before deciding whether to implement a second stage of completing the well as a production well.

In support of its case that the primary purpose of Well J03 was first to appraise and resolve the subsurface uncertainties and then to decide whether or not to complete the well as a production well, NSE relied upon a passage in Section 8 of the Well Proposal stating that “If successful, the well will be completed as a production well in the Jacky development.” But this is not indicative that the primary purpose of drilling the well was appraisal of data (which is not mentioned as a purpose anywhere in the document). The words “if successful” recognise that the project to drill the well might not be a success. There is no doubt that there were risks, which were known and stated in the Well Proposal. Indeed, there are risks inherent in the drilling of any production well – even a well drilled into proved reserves, because success can never be guaranteed. So, the words “if successful” recognise known risks.

It is telling that on the figures put forward for expected economic recovery of oil, both in the initial 29 September 2010 documents and in the Well Proposal, all six alternative possibilities projected going into production to produce oil, albeit in one (29 September) or two (Well Proposal) it would be in order to recoup losses, not to make an overall profit. This was how NSE understood it in their email of “concerns” dated 5 October 2010. Each document assumed that the well would go into production on all six alternative hypotheses being considered. As it was put in the Well Proposal “If the top reservoir is 50 ft deeper than prognosed, then the incremental recovery would be only 0.2 to 0.5 MMstb and, in this outcome, the well would not pay-back the investment. However it is still worthwhile to run the completion the well [sic] in this instance.” In other words the economic case put forward for drilling the well was that it would go into production on all posited variables as to the sub sea geology. This is inconsistent with any purpose being to an appraisal of the sub sea geology as an antecedent step in deciding whether to go into production.

The Work Programme and Budget signed by Ithaca and Dyas included the full £19.8m as “firm” for expenditure in 1Q 2011. It was a programme and budget for the drilling of a well which included the elements which were necessary to complete it as a producer. It was not a programme or budget under which the approval was limited to the expenditure for drilling the well up to the point which would provide further information as to the sub sea geology. It did not treat the further work and expenditure necessary to put the well into production as something which was being left for further consideration and authorisation in the future in the light of what was found. The element of work which comprised completion of the well as a producer was unconditionally approved and the expenditure for it unconditionally authorised. Had the primary purpose of the well been one of appraisal, with possible production only, dependent on what was found, one would have expected only a work programme and budget for that stage; or at most a treatment of the project as a two stage project with the work and expenditure on stage one being firm and on stage two being contingent. The Work Programme and Budget treated it as a one stage programme and budget for both elements.

Similarly, the AFE was for the full drilling and completion of the well as a production well, as its title confirmed. It was not a two stage authorisation which would require approval once the drilling had taken place, so as to decide whether the completion phase should go ahead. This was what Ithaca and Dyas signed on 3 November 2010 and 1 December 2010 respectively.

Dyas’s Managing Director’s email of 1 December 2010 confirmed that its Executive Board of Directors had given approval to “drill and complete” Well J03. Despite the fact that Dyas had earlier been considering whether to “start to look at risking of this almost on an exploration basis.”, that was not the basis upon which Dyas’s management approved the project. The approval was for the drilling and completion of the well as a production well.

As I have recited above there are numerous references to the Well as a production well or producer in the contemporaneous emails and correspondence of the parties and Senergy at the time. Such descriptions are not determinative, but it is significant that no one cavilled at the time with that description of the project. In particular NSE did not dissent from that description and categorisation at the time the proposal was under discussion. The categorisation given to the Well by Ithaca and Dyas is not just a question of labelling. It reflects the substance of what they understood themselves to be engaged in considering. It is of significance that there is not a single contemporaneous document which records the primary objective or purpose of Well J03 as being appraisal, or which categorises the well as appraisal. On the contrary, NSE, like others referred to it as a producer or production well: see for example the text of Mr Powers’ email to Gemini on 26 October 2010 which states as its subject, “Jacky 2^nd Producer”, and whose text refers to the proposed well as a “second production well” or a “second producer” in several places.

The Work Programme and Budget was put forward as a production WPB in accordance with clause 13 of the JOA. Mr Kyle gave consideration to whether the proposed WPB should be a development WPB or a production WPB. He decided (in my view correctly) that it should be a production WPB. The proposal to drill the well was not put forward as an appraisal WPB under clause 11 of the JOA and no one at the time suggested it should have been.

NSE’s letter of 10 November 2010, stating its reasons for opposing the drilling of the Well, concludes by Mr Anderson saying that he believed all parties would be better served by ”aligning themselves on an agreed workscope involving further appraisal of” the Jacky Field, rather than pursuing Ithaca’s proposal which was “a marginal well”. Implicit in this exhortation was the view that the well proposed by Ithaca was not for the purposes of appraisal.

If further evidence were needed that Ithaca was planning to complete the Well without waiting for the results of data collection, it is to be found in its letter of 7 January 2011.

For all these reasons, and without any real hesitation, I conclude that Well J03 was not an appraisal well within the meaning of clause 14.2.2(ii)(d) of the JOA.