Santos (Bol) Pty Ltd v Apache Northwest Pty Ltd - [2016] WASC 225

JURISDICTION : SUPREME COURT OF WESTERN AUSTRALIA
IN CIVIL

CITATION: SANTOS (BOL) PTY LTD -v- APACHE NORTHWEST PTY LTD [2016] WASC 225

CORAM: CHANEY J

HEARD: 14-16 DECEMBER 2015

DELIVERED : 27 JULY 2016

FILE NO/S: CIV 2924 of 2013

BETWEEN: SANTOS (BOL) PTY LTD
Plaintiff
AND
APACHE NORTHWEST PTY LTD
Defendant

Catchwords:

Contract - Commercial contract - Joint venture operating agreement - Proper construction - Programme and budget

Legislation:

Offshore Petroleum and Greenhouse Gas Storage Act 2006 (Cth), s 161, sch 6
Petroleum (Submerged Lands) Act 1967 (Cth), s 52

Result:

Claim dismissed

Category: B

Representation:

Counsel:

Plaintiff: Mr B Dharmananda SC & Mr D J Jackson
Defendant: Mr E C Muston SC, Mr B D Luscombe & Ms A A Gomez

Solicitors:

Plaintiff: Herbert Smith Freehills
Defendant: Clifford Chance

Case(s) referred to in judgment(s):

Apache OilAustralia Pty Ltd v Santos Offshore Pty Ltd [2015] WASC 318
Australian Broadcasting Commission v Australasian Performing Right Association Ltd [1973] HCA 36; (1973) 129 CLR 99
Australian Casualty Co Ltd v Federico [1986] HCA 32; (1986) 160 CLR 513
Electricity Generation Corporation v Woodside Energy Ltd [2014] HCA 7; (2014) 251 CLR 640
Fitzgerald v Masters [1956] HCA 53; (1956) 95 CLR 420
Gollin & Co Ltd v Karenlee Nominees Pty Ltd [1983] HCA 38; (1983) 153 CLR 455
McCann v Switzerland Insurance Australia Ltd [2000] HCA 65; (2000) 203 CLR 579
Mount Bruce Mining Pty Ltd v Wright Prospecting Pty Ltd [2015] HCA 37; (2015) 89 ALJR 990
Pacific Carriers Ltd v BNP Paribas [2004] HCA 35; (2004) 218 CLR 451
Toll (FGCT) Pty Ltd v Alphapharm Pty Ltd [2004] HCA 52; (2004) 219 CLR 165
Wilkie v Gordian Runoff Ltd [2005] HCA 17; (2005) 221 CLR 522

CHANEY J: The plaintiff, Santos (BOL) Pty Ltd (Santos), and the defendant, Apache Northwest Pty Ltd (Apache Northwest), are each party to a joint venture operating agreement (JOA) originally made on 18 February 1992. The JOA relates to a gas field, known as the John Brookes gas field, which is the subject of a production licence (WA‑29‑L) granted under the now repealed Petroleum (Submerged Lands) Act 1967 (Cth) (PSL Act). That Act was repealed and replaced by the Offshore Petroleum and Greenhouse Gas Storage Act 2006 (Cth) (OPGGS Act).
The JOA governs the terms of a joint venture in which Santos holds a 45% interest and Apache Northwest holds a 55% interest.
Production of gas from the John Brookes gas field commenced in September 2005. Gas drawn from the field is transported by over 55 km of pipeline to be processed at facilities located at Varanus Island. There are two processing facilities on Varanus Island, each of which has been used to process gas drawn from the John Brookes field. One facility is owned by participants in a joint venture known as the East Spar Joint Venture, the participants of which are Santos which holds a 45% interest and three entities related to Apache Northwest (East Spar Apache participants) which together hold a 55% interest. The other facility is owned by participants in a joint venture known as the Harriet Joint Venture being Apache Northwest, Harriet (Onyx) Pty Ltd, a related entity of Apache Northwest, and Kufpec Australia Pty Ltd. Apache Northwest and the East Spar Apache participants are subsidiaries of Apache Energy Ltd (Apache Energy).
The dispute in these proceedings concerns a project which Apache Northwest has partially implemented to install compression equipment at the inlet point of the East Spar Joint Venture processing facility at Varanus Island. The project is referred to as the Varanus Island Compression Project (VICP), the purpose of which is to boost the pressure of gas as it enters the processing facilities on the island in order to bring it to a suitable operating pressure within the processing facilities. The forecast cost of the VICP is approximately A$261.8 million. Santos contends that Apache Northwest pursued the VICP without authorisation by the operating committee under the JOA and without Santos' participation, and thereby breaches the JOA. There is little in the way of factual dispute between the parties, and the question of whether or not Apache Northwest acted in breach of the JOA turns on questions as to the proper construction of the JOA. Santos seeks various declarations, damages or alternatively repayment of amounts paid by Santos under protest in relation to the VICP, and an order for payment of interest on any damages or amount found to be repayable.
In order to consider Santos' claim, it is necessary to set out the relevant provisions of the JOA and review the facts which have led to the present dispute.

JOA

The JOA was originally an agreement between Western Mining Corporation Ltd, Bridge Oil Ltd and Australasian Oil Exploration Ltd. It is common ground that after several changes of parties to the JOA and their percentage interests under it, Santos and Apache Northwest have held the percentage interests referred to above since 17 March 2004 and Apache Northwest has at all material times been the 'Operator' of the joint venture.
The recitals record that the parties agreed to participate in the exploration for petroleum in the Permit Area and the development of any discoveries of petroleum in accordance with the terms and conditions contained in the JOA. Permit Area was defined as the area the subject of a Joint Licence, which in turn meant Petroleum Licence WA‑214‑P or any other licence issued for the purpose of operations under the JOA. It is recited that the parties desire to enter the JOA for the purpose, amongst other things, of appointing the Operator and to define their respective rights, interests and obligations in respect of the exploration for petroleum and development of discoveries in the Permit Area. The recitals to the JOA also provide:
The scope of this Agreement and the terms and conditions upon which the Parties have agreed to participate in exploration for the development of Petroleum are contained in this Agreement.
Section 1.01 of the JOA contains definitions. 'Joint Operations' are defined to mean:
… all operations conducted in accordance with this Agreement by or on behalf of all of the Parties.
'Joint Property' is defined to mean:
… all property acquired or held for use in connection with Joint Operations including the Joint Licence.
'Programme' means:
… any programme of Joint Operations including any variations thereto made from time to time in accordance with this Agreement …
'Sole Risk Development' means:
… a development of a Discovery carried out by less than all the Parties under Article XI [of the JOA].
'Budget' means:
… a budget, including any variations thereto made from time to time in accordance with this Agreement in respect of a Programme.
Section 2.01 sets out the objects and percentage interests under the JOA. It reads:
The Parties agree to participate in Joint Operations for the exploration and, if appropriate, the development and production of Petroleum within the Permit Area and each Party undertakes to commit its Percentage Interest share of all Joint Property and further agrees not to partition or to seek to partition or deal with its Percentage Interest or part thereof otherwise than in accordance with this Agreement.
The Joint Property shall be owned by the Parties in undivided shares as tenants in common in proportion to their respective Percentage Interests. In respect of Joint Petroleum, the Parties or such of them as are not in default hereunder, as specified in Article XII, shall own and, unless otherwise specified under Article XIII, shall have the right and obligation to separately take in kind and dispose of its Percentage Interest in the total quantities of Joint Petroleum produced and available under this Agreement.
Section 2.03 provides:
A Party shall not conduct any operation under, or exercise any rights conferred by, a Joint Licence except in accordance with the provisions of this Agreement.
The rights referred to in s 2.03 are found in s 52 of the PSL Act. That section provides that a licence authorises the licensee, subject to the Act and Regulations and in accordance with the conditions to which the licence is subject, to recover and explore for petroleum in the licence area, and to carry on such operations and execute such works in the licence area as are necessary for those purposes. The terms of s 52 of the PSL Act are materially reproduced in s 161 of the OPGGS Act.
Article III deals with the appointment of the Operator. Article IV deals with the authority and duties of the Operator.
Section 4.01 gives the Operator the right and obligation to conduct Joint Operations 'under the overall supervision and control of the Operating Committee'. Section 4.02 sets out the duties and responsibilities of the Operator. They include the preparation of programmes, budgets and AFEs pursuant to the provisions of the JOA. 'AFEs' are authorities for expenditure, which are provided for in Article IX of the JOA. The duties and responsibilities also include the 'implementation of such Programmes and Budgets as shall, together with the relevant AFEs, have been approved by the Operating Committee'.
Sections 4.04(b) and 4.04(c) provide:
4.04(b)Operator shall obtain competitive tenders on proposed contracts for the Joint Operations where the cost thereof is or is likely to exceed $100,000 (or such other amount not less than $100,000 as may from time to time be determined by the Operating Committee) except where in the reasonable opinion of the Operator it is necessary for emergency reasons or not practicable to obtain competitive tenders or where relieved of such obligation by the Operating Committee.
4.04(c)In the case of any proposed contract for the Joint Operations where the cost thereof will or is likely to exceed:
(i)in the case of contracts for drilling rigs and construction operations and all contracts under a development or production Budget (other than for seismic operations) ‑ $1,000,000;
(ii)in the case of contracts for technical services and seismic operations and all contracts under an exploration or appraisal Budget (other than for drilling rigs and construction operations) - $500,000;
or such other amounts as may from time to time be determined by the Operating Committee, the Operator may not enter into any such contract without the prior approval of the Non‑Operators. Where the Operator seeks such approval, the Non‑Operators shall be required to reply to the Operator within fourteen (14) days of the Operator's request. No reply means deemed approval.
Article V establishes the Operating Committee. Section 5.01 specifies that the Operating Committee 'shall exercise supervision and control of all matters pertaining to the Joint Operations'. Its specific powers and duties include the consideration, revision and approval or disapproval of all proposed programmes, budgets and AFEs prepared and submitted to it.
The Operating Committee is to consist of one representative appointed by each of the parties (s 5.02).
By s 5.08, each party has a voting interest equal to its percentage interest. The requisite majority for particular decisions is prescribed in Appendix A to the JOA. It provides that the majority required in respect to exploration or appraisal Programmes and Budgets for Joint Operations, or any other matters, is two or more parties holding an aggregate percentage interest of 65% or more. In effect, therefore, unanimous resolution is required.
Article VI deals with exploration and appraisal Programmes and Budgets. Section 6.01 requires the Operator, in each year, to submit to the parties a proposed exploration Programme and Budget for the next year. Section 6.02 provides that, in the event of a discovery and if the Operating Committee decides that the discovery is likely to contain petroleum in commercial quantity, the Operator is required as soon as practicable after that decision is made to submit a proposed appraisal Programme and Budget for the discovery which is to include, but is not limited to, the wells to be drilled, other projects and works to be undertaken, and the information required under Article IX (to which I will refer below).
Section 6.03 requires the Operating Committee to consider each exploration and appraisal Programme and Budget within a specified time and make such amendments or revisions as might be proposed and approved by the Operating Committee. Approval of a Programme and Budget authorises and obliges, subject to AFE approval, the Operator to proceed with the Programme and Budget.
Section 6.06 deals with amendment of approved exploration or appraisal Programmes and Budgets. It permits any party, '[a]t any time', to propose an amendment and, where that is done, requires the Operator to prepare and submit a revised Programme and Budget incorporating the amendment and for approval by the Operating Committee of the amended or revised Programme and Budget.
Article VII deals with development Programmes and Budgets. Section 7.01 provides:
As soon as practicable after the Operating Committee has considered the information obtained from an appraisal Programme, the Operating Committee shall determine whether or not such Discovery has resulted in the delineation of Petroleum in commercial quantities to proceed to development of the Discovery. If the Operating Committee decides to instruct the Operator to commence the preparation of a development Programme in respect of the Discovery the Operator as and when instructed by the Operating Committee shall nominate in the Permit Area a block selected by the Operating Committee for the purpose of the making of a declaration of a location (in accordance with and as defined in the Act). The Operator and the Parties shall use their best endeavours to ensure such location is declared.
Section 7.02(a) provides:
If the Operating Committee decides to develop the Discovery, as soon as practicable after such decision the Operator shall submit to the Parties a proposed development Programme and Budget for the Discovery which shall include but not be limited to:
(i)the projects and other work to be undertaken;
(ii)the information required under Article IX including a preliminary estimate of operating costs for the first year of operations;
(iii)the manner in which the development is to be managed; and
(iv)an estimate of the date of commencement of production and the annual rates of production;
(v)such other information as the Operating Committee may have required the Operator to provide.
The Operating Committee is required to approve or reject the development Programme and Budget within 90 days of its submission (s 7.02(b)). Section 7.02(b) provides:
The proposed development Programme and Budget shall be subject to consideration, revision and approval by the Operating Committee. The Operating Committee shall meet to consider such proposed development Programme and Budget as soon as practicable and to make such amendments or revisions thereto as may be proposed by any of the Parties and agreed to by the Operating Committee. The Operating Committee shall by voting in accordance with Section 5.08(b) vote, approve or reject the development Programme and Budget within ninety (90) days of its submission.
If the development Programme and Budget is approved, then the parties must decide within 90 days of that approval whether to participate in respect of its percentage share in the development of the discovery. Section 7.02(d) deals with the position if the parties do not decide unanimously to participate in the development of the discovery. It provides:
If a development Programme and Budget is approved by the Operating Committee, each of the Parties shall decide within ninety (90) days of such approval, or such longer period as the Operating Committee may agree, whether to participate in respect of its Percentage Interest share in the development of the Discovery, and the Operator shall, subject to Sections 7.03(b) and 9.02, thereafter be authorised and obliged to proceed in accordance with it. In that event, the Operator shall submit an application to the Designated Authority on behalf of the Parties for a Production Licence in respect of so much of the area of the location declared under Section 7.01 as the Operating Committee considers necessary for the development of the Discovery. The Operator and the Parties shall use their best endeavours to ensure such Production Licence is obtained. If the Parties do not decide unanimously to participate in the development of the Discovery, the provisions of Article XI shall apply (mutatis mutandis).
Section 7.03(a), (b) and (c) provides:
The Operator shall in addition to the report required each month under Section 9.03(e), in each year, review the approved development Programme and Budget and submit to the Parties a report thereon together with a review of and any recommended amendments to such development Programme and showing matters listed under Section 7.02(a) and the information required under Article IX.
At any time any Party may, by notice to all the other Parties, propose that an approved development Programme and Budget and/or an approved AFE be amended. The Operating Committee shall consider such proposal and, if the Operating Committee so requires, the Operator shall prepare and submit to the Parties a revised development Programme and Budget and/or AFE incorporating any such amendments and showing in the case of a Programme and Budget the matters listed under Section 7.02(a). To the extent that any such amendment or revised development Programme and Budget and/or AFE is approved by the Operating Committee in accordance with Section 5.08(b), the approved development Programme and Budget and/or AFE shall, subject to Section 9.03(d), be deemed amended accordingly.
The Parties recognise that at the time of approval of a development Programme and Budget it may be necessary for them to meet together to consider whether any provision of this Agreement may be found wanting at the development phase and, if so, to negotiate in good faith and endeavour to agree on any amendments or additions hereto or replacement hereof which may be considered necessary and desirable. PROVIDED THAT until a development agreement is finalised this Agreement shall to the extent it is able govern any matters which arise.
Article VIII deals with production of Programmes and Budgets. Section 8.01(a) and (b), which is headed 'Annual Programme and Budget', provides:
The Operator shall not later than four months prior to the expiry of the year prior to the year in which production commences and each subsequent year, submit to the Parties a proposed production Programme and Budget for the next year which shall include but not be limited to:
(i)the projects and other work to be undertaken;
(ii)the information required under Article IX;
(iii)an estimate of the date of commencement of production (if appropriate) and of the total production by month and maximum daily rate to be achieved in each month; and
(iv)such other information as the Operating Committee may have required the Operator to provide.
The proposed production Programme and Budget shall be subject to consideration, revision and approval by the Operating Committee. The Operating Committee shall consider such production Programme and Budget and make such amendments or revision thereto as may be proposed by any of the Parties and as may be agreed. If for any reason the Operating Committee is unable to approve a production Programme and Budget prior to the expiry of the current year, the Operating Committee shall be deemed to have approved a Programme and Budget which on the final vote of the Operating Committee attracted the highest Percentage Interest vote and the Operator shall thereby be authorized and obliged to proceed in accordance with that Programme and Budget.

Section 8.03 provides:
The Parties recognise that prior to the commencement of regular production of Petroleum from any development it shall be necessary for them to meet together to determine and agree on more detailed programming and budgeting provisions to apply to the production phase of Joint Operations. The Parties hereby agree that their respective representative shall meet together as and when necessary and upon the request of any of them for this purpose and also to consider whether any other provisions of the Agreement may be found wanting at the production phase and, if so, to negotiate in good faith and endeavour to agree on any amendments or additions hereto or replacement hereof which may be considered necessary and desirable.
Article IX deals with expenditure in relation to costs and expenses. Section 9.01(a) authorises the Operator to 'make such expenditure and take such actions as may be approved by the Operating Committee or as are authorised under Section 9.01(b)'.
Section 9.01(b) authorises the Operator to make expenditure in accordance with the accounting procedure, which is found in Appendix B to the JOA, or to take any action necessary to safeguard lives or property or prevent pollution.
Section 9.02 imposes a requirement on the Operator to submit an AFE to the Operating Committee prior to incurring any expenditure. It provides:
Subject to Sections 9.01(b) and 9.03(c), the Operator shall, before entering into any commitment or incurring any expenditure under any of the categories included in an approved Programme and Budget, submit to the Parties an AFE therefor with a request for the Operating Committee to approve the same within 14 days after receipt. Provided that where a response from any Non‑Operator is not received by Operator within 14 days of dispatch of an AFE the Operator shall send a reminder notice to such Non‑Operator requesting approval of the relevant AFE. The AFE shall include the information set out in, and be prepared in accordance with, the following provisions of this Article. Provided that the AFE does not exceed the approved budgeted amount for the item covered thereby by more than 10 per cent (10%) of the approved budgeted amount and, provided further that the AFE is within the operational or technical scope of the approved budget amount to which it relates, the approval by any Party of the AFE shall not be unreasonably withheld. Where no response is received from a Non‑Operator within 7 days of receipt of the reminder notice, that Non‑Operator shall be deemed to have approved that AFE.
Section 9.03 deals with budget and AFE procedures. Section 9.03(a) requires the Operator to divide the total budget into categories and to include a monthly forecast of cash requirements throughout the budget period. It continues:
Each Budget shall contain the estimated final cost of all activities either commenced or expected to commence during the budget period and the amount estimated to be spent and shall include manpower hours as well as rates for Operator owned plant and equipment.
Article X deals with 'Sole Risk Drilling' and is not relevant for present purposes.
Article XI deals with 'Sole Risk Development'. It permits any party to undertake development at its sole risk in circumstances where the Operating Committee has voted against a development Programme and Budget being prepared for a particular discovery following completion of an approved appraisal Programme. In that event, any party may give notice to the other parties of an intention to prepare a development Programme and Budget for the discovery. Provision is made for parties to elect to participate in the Programme and Budget. Any party that does not participate in the development of the discovery has no further rights in relation to the sub‑area (as constituted in accordance with s 11.02(i)).
By s 17.06 of the JOA, the accounting procedure set out in Appendix B to the JOA is made part of the JOA. Any provision of the main body of the JOA which is inconsistent with the provisions of the accounting procedure prevails over the provision of the accounting procedure.
Clause 1.5 of the accounting procedure enables the Operator to request the parties to advance its percentage interest share of estimated cash requirements for the succeeding month for joint operations under the JOA.
Clause 1.8 of the accounting procedure provides an entitlement to a party to protest or question the correctness of a cash call. It provides that all cash calls and billing statements rendered to a party by the Operator are presumed to be true and correct after 24 months unless within that period a party takes written exception thereto and makes a claim on the Operator for adjustment.
Clause 3.5 of the accounting procedure provides:
Fixed Assets which are owned by one of the Parties and which are sold to the Parties for the Joint Operations shall be priced at fair market value. In determining the fair market value of an asset, consideration will be given among other things to the age, condition, location and local market value.
Clause 3.6 of the accounting procedure provides:
For services rendered to the Joint Operations by field equipment or facilities exclusively owned by a Party including but not limited to transportation equipment, drilling and cleanout tools, workshops, water, fuel and power systems, warehouses, and the like, the owner will charge for such services at rates not in excess of fair market value. In determining the fair market value of such services, consideration will be given to rates charged by other potential suppliers, location, quality and timing of service and any other relevant factors. The cost of repairing damage sustained to such equipment or facilities arising out of or in the course of its use in connection with the Joint Operations shall be charged to the Joint Account provided always that, if the cost of such damage is recoverable from any underwriters or any third Party, the recovery will be credited to the Joint Account.

Gas extraction mechanisms

To understand the events giving rise to dispute in these proceedings, and the function of the VICP, a basic understanding of the mechanisms for extraction of gas, or hydrocarbons, from an underground reservoir is helpful. The mechanisms were explained by Dr Stephen R Brand, a witness called by Santos. Dr Brand has a doctorate in geology and extensive experience in the oil and gas industries. His explanation of the mechanisms of gas extraction was not contentious.
Dr Brand explained that a reservoir is an area in the subsurface of the earth where hydrocarbons have accumulated over geologic time. A hydrocarbon reservoir is different from a water reservoir. It consists of a porous and permeable rock layer which has the capacity to store and allow the flow of hydrocarbons, and has a mechanism such as impermeable rock to prevent the escape or migration of the hydrocarbons.
When well bores are drilled from the surface, it is necessary that there be a force within the reservoir that moves the hydrocarbons up the well bore to the surface of the earth. There are two dominant variable conditions in a reservoir, namely pressure and temperature. Temperature is usually constant but changes in volume and sources of pressure determine how much energy is capable of moving hydrocarbons within the reservoir. The energy creates a pressure differential which causes the hydrocarbons to flow to the lower pressured well bore. The forces that provide the energy are commonly known within the industry as reservoir drive mechanisms.
In a natural gas field, such as the John Brookes field, there are two basic drive mechanisms by which the gas reservoir is typically produced. They are a gas expansion drive, also known as a depletion drive, or a water drive, also known as an aquifer drive. In a water drive reservoir, encroaching water fills the part of the reservoir space originally occupied by gas as the gas is removed. In his evidence, Dr Brand was asked to assume that the John Brookes field production history indicates that there is no significant aquifer support in the reservoir capable of maintaining a level of pressure at a relatively constant rate until such time as the water reached the well.
The alternative drive mechanism is a gas expansion/depletion drive. The depletion drive is characterised by the expansion of the compressed gas remaining in the reservoir due to a pressure decline as the gas is produced. The reservoir is a closed system (that is, no water drive is present and recovery of the gas at the surface is dependent upon the pressure being provided by volume expansion from within the reservoir). The position is analogous to compressed air in a sealed tank. As the air in the tank is allowed to escape when the valve is opened, the pressure within the tank will decrease and the flow of air from the tank also decreases. Similarly, as reservoir pressure decreases because gas is being removed, the productivity of the gas wells also declines. In conventional, good quality gas reservoirs, recovery of gas from a depletion reservoir will generally be in the range of 50 to 70%, so that approximately 30 to 50% remains in the reservoir rock. That recovery rate can be increased to something in the range of 80% by the addition of compression at the surface. That may be necessary to ensure that the pressure at which the gas arrives at the point of processing is sufficient for processing. It is to that end that the VICP was contemplated.

The facts

On 2 September 2003, the Operating Committee resolved, in accordance with s 7.02(a) of the JOA, that the Operator should commence preparation of a development Programme and Budget in respect of the John Brookes field. A development Programme and Budget was issued by Apache Northwest, as Operator, on 6 October 2003.
In the executive summary to the development Programme, the following appears:
It is believed there will be moderate aquifer support with a consequent recovery factor expected to be in the order of 71%. Regardless, the development plan is flexible and if there is insufficient aquifer support, compression can be installed onshore Varanus Island to maximise reserves recovery.
The proposed development Programme made several express references to the processing of the gas from the John Brookes field on Varanus Island. The development Programme continued:
The cost of the project, including three wells, the platform, pipeline and de‑bottlenecking of the Varanus Island Facility is estimated to be A$165 million (excluding possible costs for additional processing equipment on Varanus Island).
Clause 2.4.1 of the development Programme provided:
Government approval of the field development plan is required prior to obtaining a Production License to produce the field. Approval of the field development plan involves two stages (see figure 2.2):
•preparation and issue of a 'preliminary development plan' to gain approval of the development concept, then
•preparation and issue of the 'finalised development plan' together with the application for a Production License.
Approval applications are made to the Joint Authority (JA), consisting of the Commonwealth Minister for Industry, Tourism and Resources and the WA, Dept of Industry and Resources.
The first stage to gaining JA approval of the development concept has been commenced. Stage two of the approvals process will be commenced following receipt of the JVP approvals of the development programme and budget.
Clause 4.8 discusses the recovery factor for the field. It provided:
The recovery mechanism for all three Top Barrow reservoirs in the John Brookes Field is expected to be a combination of pressure depletion combined with a poor water influx from the aquifer. This is based on the lack of hydraulic pressure communication over the field and experience from the nearby East Spar field. Table 4.5 summarises the calculation of the recovery factor for all three gas zones based on only a 10 percent volumetric sweep due to aquifer influx and an average field abandonment pressure of 8.681 MPa (1250 psia). This results in a gas recovery factor of about 71% for all three reservoirs.
The drive mechanism is expected to be partial depletion drive (some aquifer support). It is not expected that compression will be necessary to deplete the reserves. Nonetheless the development concept allows onshore compression to be installed when and if necessary …
The possibility of onshore compression was also referred to at cl 5.1.1 of the development Programme where it was said:
Although it is believed the reserves will be fully recovered through partial depletion drive, the option to install onshore compression on Varanus Island if depletion necessitates ensures that in any case reserves recovery will be maximised. Onshore compression also ensures offshore facilities are minimised with significant benefits to personnel safety and minimum inventories of hydrocarbons/chemicals that represent environmental hazards.
Clause 6.3 of the development Programme concerns the basis of completion design. It provided:
Basic completion philosophy during the development of John Brookes will be to maximise reserves recovery whilst gaining an acceptable deliverability from each well. It is possible multiple hydrocarbon zones (as in Thomas Bright‑1) may be intersected in the development wells. Consequently the completion strategy described below is flexible, catering for a variety of well outcomes whilst ensuring maximum reserves recovery from any sand package.
In cl 6.3.5, it is said that the development plan would 'continue to evolve over the production life of the field'. That statement was said by Santos to support the proposition, the significance of which will be discussed later, that 'development' and 'production' may temporarily overlap.
Clause 8 noted that it is envisaged or proposed that the operators of the Varanus Island facilities would be approached to provide support to operate the John Brooke facilities on behalf of the John Brookes joint venturers.
Clause 11 of the development Programme identifies the breakdown of the capital costs of A$165 million. That sum does not include any amount for inlet compression. Nor is there any reference to inlet compression in the assumptions underlying the project economics referred to in cl 12.
On 7 October 2003, the Operating Committee resolved to approve the development Programme and to commence development under the terms of the JOA.
On 15 October 2003, as foreshadowed in cl 2.4.1 of the development Programme, Apache Northwest, as Operator, submitted a preliminary field development plan to the regulatory authority. Clause 4.8 of the preliminary development plan noted that the drive mechanism is expected to be partial depletion drive (with some aquifer support). It continued:
It is not expected that compression will be necessary to deplete the reserves. Nonetheless the development concept allows onshore compression to be installed when and if necessary.
The clause then explains why, if late field life compression is necessary, onshore rather than offshore compression is to be preferred.
On 30 January 2004, Apache Northwest issued an updated development Programme and Budget to reflect the results of some additional engineering design work which had been undertaken and the results of discussions with the East Spar Joint Venture parties. The clause dealing with the recovery factor was renumbered from 4.8 to 4.9, and its terms were amended. After substantially reproducing the first paragraph of the original cl 4.8, cl 4.9 of the updated development Programme and Budget provided:
The drive mechanism is expected to be partial depletion drive (some aquifer support). It is not expected that compression will be necessary to deplete the reserves. Nonetheless the development concept allows onshore compression to be installed if necessary at the plant inlet. Reserves recovery is assured as,
•the pipeline diameter has been sized (see section 5) to ensure that pipeline pressure losses are limited even when operating at lower operating pressures including those experienced during compression.
•at the low flow rates at the end of the field life, there will be negligible difference between final abandonment pressure when comparing a development with offshore or shore based compressors and reserves recovery is the same.
The contents of the updated development Programme, so far as relevant to the present proceedings, were otherwise unchanged.
In accordance with the requirements of s 7.02 of the JOA, the parties agreed in January 2004 to participate in respect of their percentage interests in the development of the discovery.
In October 2004, Apache Northwest submitted the John Brookes final field development plan to the regulatory authority. The reference in the executive summary to the possibility of compression insulation was unchanged from the preliminary field development plan. Under the heading 'Reservoir Simulation', cl 4.9 referred to a simulation study done in September 2004 to investigate the sensitivity of aquifer strength to recovery. After explaining the nature of the simulation, the clause continues:
Permeability was input from core data, RFT analysis and core porosity versus permeability transforms. A numerical aquifer was employed with permeability sensitivity from 1mD (essentially depletion drive) to strong aquifer support at 400 mD. The resultant recovery factor ranged from 72 to 78%.
The lower recovery factors (72%) occur in the models utilising largely depletion drive with poor aquifer support. It is recognised that compression would be economically justified in a depletion drive case and therefore would be implemented to increase recovery. However it is anticipated in the case of depletion drive that the reservoir may also be compartmentalised with potentially undrained compartments. Therefore a recovery factor of 72% has been used as a low end recovery factor estimate for the field, assuming compression is installed but some gas is trapped by compartmentalisation.
Reference to the possibility of onshore compression, in the same terms as contained in the preliminary field development plan, was made in cl 5.1.3.1. Similarly, reference was made, in cl 6.2.5, to the continuing evolution of the development plan over the production life of the field. The capital cost estimates remained at A$165 million and did not include any reference to inlet compression.
The final field development plan attached, as Appendix F, a technical paper prepared in response to the preliminary field development plan by the relevant State and Commonwealth departments. It raised various questions about the reservoir drive mechanisms and compression. Appendix G to the final field development plan contained the proponents' response to the joint technical paper. It noted that compartmentalisation (of the gas reserves in isolation from nearby gas fields) could increase compression needs but that the land based processing facilities allow for straightforward expansion of compression power if required. In relation to compression, the response provided:
Compression
The level of aquifer support seen in the reservoir is believed to be adequate to drain the reserves. The impact of varying aquifer support will be to (see also discussion section 4.9 of the FDP);
•in the case of limited aquifer support, it will be necessary to increase well numbers to maintain target offtake rates and to then install additional compression power to reduce wellhead pressure for good gas recovery. The production life will have a tail and it will take longer to produce the reserves.
•in the case of strong aquifer support, compression will not be required and it will be easier to maintain high production rates until water breakthrough. However gas recovery could be impacted by sweep efficiency and level of residual gas saturations.
Compression can be provided, if necessary, with a lead time of approximately twelve months. The compressor would be installed onshore downstream of the slug catchers and would supplement the existing compression power. The compression power necessary would be designed to meet the contractual offtake commitments. Compression is flexible and can be designed to allow the wellhead pressure to be dropped to as low as necessary during the field life. The compressor installation is estimated to cost A$20‑24 million dependent on power requirements. The compressor being based in the existing plant would not impact manpower requirements and its operation would incur a negligible increase in plant operating costs. Monitoring of well production decline rates and pressures will provide adequate lead time to install the compressor if required.
Due to the adequate sizing of the pipeline between the platform and the onshore facilities the abandonment wellhead pressure, at the low rates seen at abandonment, are similar regardless of whether the compressor is based in the onshore facilities or on the offshore platform. Conversely an offshore compressor installation in this situation would have substantial platform design, operating cost, manning, environmental and safety implications that would ultimately increase the abandonment rate for the field and reduce recovery. Therefore an onshore compressor installation in this situation is recommended.

In relation to development options, the response referred to the criteria for development selection as including maximising gas recovery, achieving contractual offtake rates and maintaining flexibility for the uncertainties in reservoir depletion scenarios. It asserted that the proposed development option of processing through the existing Varanus Island facilities 'and the possibility for later installation of compression onshore meets all the criteria set'.
On 21 December 2004, production licence WA‑29‑L was granted to Apache Northwest and Santos for production of gas from the John Brookes field under the PSL Act.
Production of gas from the John Brookes field commenced in September 2005.
It is apparent that, by 2010, Apache Northwest (through its parent company Apache Energy) came to the view that inlet compression would be required for, or at least would be desirable for, maximisation of the production of gas from the John Brookes field. In December 2010, an Apache Energy internal memorandum proposed that front end engineering and design (FEED) for John Brookes inlet compressors together with what were referred to as Varanus Island export compressor projects should be undertaken, and an AFE to cover FEED activities was proposed. An Apache Energy internal AFE was eventually signed in September 2011. An email sent on 5 September 2011 from Mr Nick Cooper, a senior accountant for Apache Energy, to Mr Ian Sigsworth, the engineering manager (projects group) within Apache Energy, said:
As discussed, I'd like to raise a 100% Apache AFE for the VI export and JB inlet compression FEED/S as the understanding is that Santos will not be approving or paying for anything until at least next year and so these costs should not be sitting in the JV space.
It is apparent that Santos was aware, at least by May 2011, of Apache Northwest's view that compression was required in relation to the John Brookes field production. On 18 May 2011, Keith Dowling of Apache Energy wrote to Mr Wade Bard of Santos suggesting a meeting to review 'the deliverability projections' in relation to various joint ventures, including the John Brooks joint venture. He proposed that the meeting would enable Santos to 'see where Apache is coming from with respect to the compression project'. It appears that there was a subsequent presentation made by Apache to Santos, which is recorded in a PowerPoint presentation dated 3 June 2011. The slide headed 'John Brookes Overview' suggests that well deliverability is slowly declining, driven by a depletion drive with minimal aquifer influx. A slide titled 'Observations' suggests that delivery would fall below 400 terajoules per day (TJ/d) and that inlet compression would allow an additional 350 BCF of gas to be recovered from the John Brookes field. The project timeline for a new compressor from investment decision to production was said to be approximately 30 months. The presentation concluded with recommendations that compression should be installed in 2013/2014 and should be included in the 2012 work plan and budget.
A further presentation in relation to the John Brookes compression project was made on 5 July 2011. After recapping the substance of the 3 June 2011 meeting, the presentation dealt with the specifics and timing of the proposed implementation of the compression project. It was noted in the presentation that FEED work performed to date had been funded 100% by Apache.
On 4 May 2012, Apache Energy, acting on behalf of the East Spar Apache participants, wrote to Santos. The letter attached an AFE for FEED studies relating to two additional inlet compressors and potentially an additional export compressor to be installed on Varanus Island. The letter referred to previous discussions on a number of occasions with Santos' technical personnel in relation to the proposal. The letter repeated that the inlet compressors would enable the recovery of an additional 350 BCFE from the John Brooks field. The letter continued:
Because the ESJV/JBJV will receive the principal benefit of the inlet compressors this opportunity is presented for investment by ESJV. However, the only practical way to obtain suitable space for the additional compressors is by reclaiming part of the bund, which is on the Harriet JV lease. Apache is working legal and commercial issues with the Harriet JV and we are confident that we will reach a commercial agreement with the Harriet JV which will permit the compressors to be located as described.
The proposed authority for expenditure was for an amount of A$7,300,000.
On 31 May 2012, Santos wrote to the East Spar Apache participants declining to approve the AFE. The letter asserted that Santos had 'insufficient insight into the benefits of the additional compression proposed', and had insufficient information to conclude that the compression project was economic. The letter said that Santos expected that inlet compression may become viable if the expenditure were incurred at the time when 'John Brookes comes off plateau', which was expected 'to occur later this decade'. Santos also asserted that Apache had no authority to negotiate with the Harriet Joint Venture participants in relation to the use of land on Varanus Island for the purpose of the inlet compression project.
On 11 June 2012, Apache Energy responded. It asserted that, by rejecting the proposed AFE, 'Santos therefore obliges Apache to perform the work covered by the AFE on a sole risk basis'. The letter concluded:
As stated in our letter of 4 May 2012, Apache is planning to take FID on the compression project in September 2012, subject to satisfactory results from the FEED work. While reiterating our acknowledgment of our potentially different economics, Apache sees a clear technical and business case for the inlet compression to recover additional John Brookes reserves, and consequently intends to continue with the FEED work covered by the above‑referenced AFE. Since Santos has rejected the FEED AFE and retains the option not to participate in the compression project, Apache considers it essential that we retain the option to progress the inlet compression project on a 100% basis. If Apache goes on to execute the project on that basis, we will - without obligation - consider entering into negotiations with Santos to allow Santos to utilise these facilities by means of a tariff payment.
Between August 2012 and October 2012, Apache Northwest approved several AFEs totalling in excess of $300 million in relation to the VICP.
On the pleadings, it is admitted that after 31 May 2012, Apache Energy on behalf of Apache Northwest undertook various activities which are set out in [26] of the statement of claim to progress work in relation to the installation of the inlet compressors on Varanus Island. Those included:
•the procuring of long lead items including compressors, a turbine and generator packages;
•awarding an engineering and procurement contract to Clough Projects Australia Pty Ltd to conduct detailed design and engineering, drafting, package specification and tender reviews;
•awarding a contract to Australian Portable Buildings Pty Ltd to upgrade an accommodation camp on Varanus Island;
•awarding a contract to Solar Turbines to purchase two compressor units with a value of approximately US$22 million and a generator to a value of approximately US$4.2 million;
•issuing invitations to tender and awarding other contracts in relation to the VICP;
•negotiating with the Harriet Joint Venture participants in relation to a lease of the land required for the purposes of the VICP;
•incurring expenditure in 2012 in the sum of $5,162,866 in relation to the VICP;
•between January 2013 and May 2013, incurring expenditure of $35,754,000 in relation to the VICP;
•between June 2013 and December 2013, incurring expenditure in the order of $87,254,000 in relation to the VICP;
•procuring a variation in pipeline licence PL‑29 held by the participants in the East Spar Joint Venture and pipeline licence PL‑12 held by the participants in the Harriet Joint Venture in order to facilitate the VICP;
•obtaining the necessary consents from the Department of Mines and Petroleum to permit the installation of infrastructure and equipment;
•submitting and procuring approval of a Construction Environmental Management Plan for the VICP from the Department of Mines and Petroleum;
•procuring approvals from the Department of Environment and Conservation in relation to the VICP;
•submitting and procuring approval for works under the Environmental Protection Act 1986 (WA) for works related to the VICP;
•procuring planning approval from the Pilbara Joint Development Assessment Panel dated 8 April 2013 for the VICP; and
•procuring a building permit under the Building Act 2011 (WA) for the VICP.
On 19 October 2012, Mr Bob Cowan, commercial manager of Apache Energy, sent an email to a number of other people within Apache. The email attached links to the JOA for two projects, including the VICP. The second paragraph of the email read:
For VICP the applicable JOA WA-214-P that covers the John Brookes field. This is an older JOA (dated 1994). Article 4 is the main area that details the contracting approvals. These thresholds are quite low, but until Santos are in the project we shouldn't need to seek their approval. Their agreement to enter the project will include approval for all contracts let upon until that date.
Under the regulations to the OPGGS Act, there are obligations to provide certain reports to government. Pursuant to those obligations, Apache Northwest provided an annual title assessment report to the regulator for the period 21 December 2010 to 20 December 2011 in relation to the John Brookes field. It specified as the activities planned for the following reporting year as the continuation of the production of gas and to initiate a project to install inlet compression on Varanus Island with the expected on‑stream date of 2015.
In November 2012, Mr Hackett of Santos requested from Apache certain documents in relation to the VICP. Amongst the documents provided was a project execution plan concerning the VICP. Reference was made to the project being managed by Apache Energy Ltd and that discussions are ongoing with Santos in respect to participation in the project. Under the heading 'JV Partner Alignment (East Spar)', the plan said:
The JV Partner (Santos) has not agreed to participate in the Project at the time of AEL approval (FID) although there is recognition that Santos will inevitably require compression capacity at some time in the future. Economics for the project have considered a number of commercial options for AEL, the outcomes of which have allowed the project to progress on the basis of 100% funding by AEL.
On 23 March 2013, Mr Faron Thibodeaux of Apache Energy sent an email to a number of persons within Apache seeking information as to when information had been provided to Mr Hackett pursuant to his request in November 2012. The information was sought to enable Mr Thibodeaux to prepare for a meeting with one John Anderson, who I assume to be a senior officer of Santos. In response, Mr Cowan said:
Most of the supporting technical info for VICP was provided to Santos by the end of December last year. As Paul mentioned we had meeting last week for them to ask any questions so they can go through their stage gate process. In order to force a decision we need to prepare a Development WPB along with a OCR [Operating Committee Resolution] which is yet to be prepared.
For GES [Greater East Spar] we were delayed in providing info with the Scope of work and Basis of Design provided in early February and the PEP provided in early March.
Like VICP we need to also prepare a Development work program and budget and OCR which will be put to the JV first before we can table a sole risk proposal. Because we cannot sole risk them on GES till the 28 August, unless we were sure Santos would approve the development, because of JOA timing we would hold off tabling the initial development WPB and OCR until 15 July.
If we table the WPB and OCR earlier than this and they reject it, we would need to resubmit it again for JV vote by the 15 July, which they if then reject again we can then sole risk them on the 28^th August.
Santos relies on this email as demonstrating that Mr Cowan considered that the VICP was properly to be treated as a development issue, rather than as a production issue.
On 18 April 2013, Mr Hackett wrote to Mr Goodacre of Apache Northwest enquiring whether Apache Northwest intended to address the work anticipated by the VICP in an Operating Committee meeting of the John Brookes joint venture.
On 18 April 2013, Mr Hackett wrote a further letter to Mr Cowan in which he said:
Apache has referred to performing the work the subject of the AFE on a sole risk or 100% basis. I would be grateful for your explanation of how Apache Oil Pty Ltd (Apache Oil) considers that it is permitted to undertake the compression project on a 100% basis - our view is that there is no such entitlement under the East Spar Joint Operating Agreement.
Mr Cowan responded on 2 May 2013. He said:
Apache Oil Australia Pty Ltd ('AO') is not undertaking work under this AFE pursuant to the East Spar Joint Operating Agreement.
The answers to the specific questions that you raise are:
•No expenditure has been incurred on the joint account for these activities.
•Apache has incurred 100% of this expenditure.
•The reference to the AFE was incorrect in the PEP.
•No expenditure is planned for the Joint Account until the matter of the Greater East Spar Project is brought to the Operating Committee of the East Spar Joint Venture.
•The PEP was provided for information only for when the matter of the Great East Spar Project is brought to the Operating Committee of the East Spar Joint Venture.
AO does intend to address the work anticipated by the VI Compression Project in an Operating Committee meeting of the East Spar Joint Venture.
AO has had no formal negotiations or discussions with the Harriet Joint Venture in respect of the VI Compression Project.
By letter of the same date, Mr Goodacre advised that Apache Northwest did intend to address the work anticipated by the VICP in an Operating Committee meeting of the John Brookes joint venture.
On 22 May 2013, Mr Hackett responded to Mr Cowan by letter. He asserted there was no capacity for Apache to undertake work in relation to joint venture assets on its own account, and that Apache Oil appeared to be acting outside its obligations under the East Spar Joint Venture operating agreement. He asserted that Operating Committee approval was required and work could not be done which was intended to pre‑empt the approach which the Operating Committee might take. Rather, the Operating Committee was required to be free to consider any proposal on its merit without being constrained by unilateral decisions taken by Operator. Mr Hackett sought an explanation from Apache Oil as to its conduct and requested that the matter of the VICP be brought to the Operating Committee of the East Spar Joint Venture at its next meeting which should be promptly called.
On the same date, Mr Hackett wrote a letter to Mr Goodacre requesting that the matter of the VICP be brought before the Operating Committee of the John Brookes joint venture at the next meeting. He also sought an undertaking that 'John Brookes joint venture property will not be modified, tampered with or otherwise dealt with, in connection with the VI compression project without Operating Committee approval'.
On 24 May 2013, Mr Cowan circulated an email to a number of persons within Apache. The emailed commenced:
We are gaining clarity on our engagement strategy with Santos regarding GES and VICP. The first step is the submission of a development work programme and budgets to respective joint venture with a proposal to undertake both projects as joint operations.
The email then set out the provisions of s 7.02 of the JOA dealing with the requirement of the Operator to submit a proposed development Programme and Budget for a discovery. It also set out s 9.03, which deals with the contents of a Budget and AFE procedures.
On 5 June 2013, Mr Cowan responded to Mr Hackett advising that Apache would not give the undertakings requested and acknowledging that a sole risk development under the JOA was first required to be proposed to the Operating Committee as a Joint Operation. He said that Apache intended 'to submit [such matters] to the Operating Committee in due course'.
On 28 August 2013, a proposed John Brookes joint venture annual work programme and budget for 2014 was provided by Apache Northwest to Santos (2014 AWPB). The 2014 AWPB provided for major capital expenditure of $251,795,779, of which $247,395,779 related to the VICP. A breakdown of those costs was contained in various documents attached to the 2014 AWPB. One of those documents was a capital work programme and budget 2013. It contained a project schedule which set out the key tasks required to be undertaken. That schedule showed work undertaken over a period of three and a half years, commencing in 2012 and concluding in mid‑2015. Major milestones were set out in cl 3.2 of the capital work programme. A table of those milestones set out both a target date and a date on which the target had either been achieved or was forecast. The target dates ranged from 20 September 2012 to 12 May 2015, and those predating June 2013 were shown as having been achieved.
In relation to JV funding, the capital works programme stated:
In order to maintain project schedule to ensure deliverability from the field is maintained Apache sanctioned the project 20 September 2012 and has approved a 100% AFE to commence work whilst awaiting Santos' approval. Upon obtaining joint venture approval to undertake the works on a joint basis, past costs incurred to date (include FEED AFE) will be charged to the joint account.
One of the other documents provided with the 2014 AWPB was a document entitled 'WA‑29‑L John Brookes Field Development Plan (Compression Update)'.
After providing a revised 2014 AWPB, which contained amendments which are not material for present purposes, Apache Northwest called a meeting of the Operating Committee to be held on 17 October 2013 to discuss the 2014 AWPB.
On 7 October 2013, Mr Raymond Lobo, Santos' representative on the John Brookes Operating Committee, wrote two letters to Mr Cowan of Apache Northwest. In the first letter, Mr Lobo asserted that there was no existing approval for the VICP in respect of joint production from the John Brookes discovery. He set out at length the history of the VICP, including the previous steps taken by Apache Energy in relation to the East Spar Joint Venture and the Spar JV. He reiterated the content of correspondence which has been set out earlier in these reasons concerning the VICP. He referred to the relevant provisions of the JOA, and asserted that the VICP is not part of the approved John Brookes development plan and is not able to be advanced as part of the annual production programme and budget. He asserted that the steps taken by Apache to advance the VICP reflect an ongoing failure by Apache Northwest to conduct operations in accordance with the provision of the JOA. He denied any obligation on the part of Santos to contribute to past expenditure which had not been authorised by the Operating Committee.
In the second letter, Mr Lobo repeated that proper procedure for consideration of expenditure in relation to the VICP had not been followed. He asserted that Apache Northwest did not have the authority to progress the VICP either on behalf of the John Brookes joint venture or at all, and sought withdrawal of the 2014 AWPB.

On 15 October 2013, Apache Northwest agreed to postpone the meeting of the Operating Committee until 30 October 2013.
On 28 October 2013, Apache responded to Santos' letters of 7 October 2013 denying the allegations of default. In particular, Apache referred to the references to the possibility of compression being installed onshore on Varanus Island in the JV final field development plan. The letter asserted that Santos had been provided with numerous communications concerning inlet compression. It denied any entitlement on Santos' part to require withdrawal of the 2014 AWPB.
The Operating Committee met on 30 October 2013. The minutes record that the parties disagreed as to whether the VICP should be progressed by way of amendment to the development plan and budget, or could, as Apache proposed, be dealt with under a production work plan and budget. At the conclusion of the meeting, Apache Northwest voted to approve the 2014 AWPB. Santos abstained from voting on the basis of its position that the 2014 AWPB was invalid.
On 22 November 2013, Santos wrote to Apache Northwest requesting a special meeting of the Operating Committee pursuant to s 5.04(b) of the JOA. Amongst the items sought to be included on the agenda was a proposal that the VICP be removed from the 2014 AWPB. That meeting was held on 11 December 2013. Santos and Apache Northwest simply reiterated their different positions in relation to the inclusion of the VICP in the 2014 AWPB and whether Apache Northwest was in breach of the JOA. Santos' motion to excise the VICP from the 2014 AWPB was submitted. Santos voted in favour of the proposal, and Apache Northwest voted against it. Apache submitted a motion to approve the 2014 AWPB as originally proposed and voted on at the meeting of 30 October 2013. Apache Northwest voted in favour of that motion, and Santos again abstained from voting on the basis of its position that the 2014 AWPB was invalid.
On 13 March 2014, Apache Northwest issued an AFE to the JV participants for expenditure relating to the VICP. In letters dated 25 March 2014, 23 April 2014, 30 May 2014 and 31 July 2014, Santos notified Apache Northwest that it did not approve the AFE of 13 March 2014.
On 18 July 2014, by which time these proceedings had been commenced, Apache Northwest wrote to Santos responding to Santos' reasons for withholding approval for the 13 March 2014 AFE. The letter referred to s 9.02 of the JOA, which provides that approval by Santos of an AFE shall not be unreasonably withheld. Apache Northwest advised that they would now proceed on the basis that Santos had approved the AFE because of its unreasonable refusal to approve it. The letter attached a cash call in relation to the VICP in the amounts of A$54,394,823 and US$17,606,704 (August 2014 cash call).
Santos paid the August 2014 cash call under protest, maintaining that it was not supported by an approved programme and budget, nor by an approved AFE, and contained other defects. Santos paid the cash calls on the basis that:
1.under par 1.8 of the accounting procedure, Santos protested and questioned the correctness of and took written exception to the cash call;
2.under par 1.8 of the accounting procedure, Santos claimed an adjustment downwards of the cash call in the amounts referred to above;
3.the payment under protest was made to avoid the consequences of being treated by the Operator as a defaulting party under the JOA; and
4.Santos would amend its case in these proceeding to include a claim for recovery of the amounts claimed in the cash call.
Subsequently, Apache Northwest issued, and Santos paid under protest, further cash calls relating to the VICP, and in particular:
•A$2,006,806 in or about September 2014 (September 2014 cash call);
•A$967,500 and US$1,477,014 in or about October 2014 (October 2014 cash call);
•A$990,000 and US$135,000 in or about November 2014 (November 2014 cash call);
•US$225,000 in or about December 2014 (December 2014 cash call);
•US$225,000 in or about January 2015 (January 2015 cash call);
•A$675,000 in or about April 2015 (April 2015 cash call);
•A$675,000 in or about May 2015 (May 2015 cash call);
•A$1,350,000 and US$450,000 in or about June 2015 (June 2015 cash call);
•A$1,440,000 in or about July 2015 (July 2015 cash call);
•US$669,029 in or about August 2015 (August 2015 cash call);
•US$18,000 in or about September 2015 (September 2015 cash call); and
•US$270,000 in or about October 2015 (October 2015 cash call).
A monthly report issued in relation to the VICP in July 2015 recorded that costs in relation to the VICP to that date were approximately A$175.4 million and the final forecast costs were A$261.8 million. At that stage, the modules associated with the project were in a long‑term storage facility and it was proposed that the project would be restarted in July 2016. That start date was subsequently varied to 1 January 2017, and the project equipment remains in storage.

The issues

The substantive dispute between the parties to this action is as to the proper construction of the JOA. Although in their pleadings each party expressed their competing constructions in more detailed terms, it was accepted at the hearing that the issues which fall for determination in these proceedings are:
(i)Is the work and costs associated with the VICP a 'development' which is only able to be approved via a programme and budget issued under s 7.02 of the JOA or an amendment of such documents under s 7.03?
(ii)If not, can a production programme and budget issued under s 8.01(a) and approved under s 8.01(b) include costs associated with works which have already been undertaken?
(iii)In either case, did Apache Northwest breach the JOA by undertaking works and incurring costs in connection with the VICP prior to obtaining the approval of the Operating Committee?
(iv)If any of the above questions are answered in the manner contended for by Santos, what is the appropriate form of relief?
In its defence, Apache Northwest pleaded defences of estoppel, misleading conduct in contravention of the Competition and Consumer Act 2010 (Cth) and Trade Practices Act 1974 (Cth), and unjust enrichment. Those defences were not pursued at trial.

Issue 1 - Construction of Articles VII and VIII

The first issue turns on the proper construction of the JOA. The principles to be applied were not in issue between the parties. Both parties referred to and adopted my summary of the applicable principles in Apache Oil Australia Pty Ltd v Santos Offshore Pty Ltd [2015] WASC 318 [170] ‑ [173], where I identified the following principles:
•A commercial contract must be given an objective construction, by giving proper effect to the text, context, subject matter and purpose of its provisions: Pacific Carriers Ltd v BNP Paribas [2004] HCA 35; (2004) 218 CLR 451, 461 ‑ 462 [22]; Toll (FGCT) Pty Ltd v Alphapharm Pty Ltd [2004] HCA 52; (2004) 219 CLR 165, 179 [40].
•The meaning of the terms of a commercial contract is to be determined by what a reasonable business person would have understood those terms to mean: McCann v Switzerland Insurance Australia Ltd [2000] HCA 65; (2000) 203 CLR 579, 589 [22] (Gleeson J) cited in Electricity Generation Corporation v Woodside Energy Ltd [2014] HCA 7; (2014) 251 CLR 640, 656 ‑ 657 [35].
•A commercial contract is to be construed so as to avoid it 'making commercial nonsense or working commercial inconvenience': Electricity Generation Corporation v Woodside Energy Ltd [2014] HCA 7; (2014) 251 CLR 640, 656 ‑ 657 [35].
•A reasonable commercial construction according with commercial efficacy or common sense is to be preferred to 'strict literal meaning' or a 'literal interpretation': Australian Casualty Co Ltd v Federico [1986] HCA 32; (1986) 160 CLR 513, 520 (Gibbs CJ); Gollin & Co Ltd v Karenlee Nominees Pty Ltd [1983] HCA 38; (1983) 153 CLR 455, 464 (Mason, Murphy, Brennan, Deanne & Dawson JJ).
•In construing a commercial contract in its context, its terms must be considered as a whole, giving consistent meaning to all its terms and avoiding any apparent inconsistency: Fitzgerald v Masters [1956] HCA 53; (1956) 95 CLR 420, 437; Australian Broadcasting Commission v Australasian Performing Right Association Ltd [1973] HCA 36; (1973) 129 CLR 99, 109 (Gibbs J).
•Preference is to be given to a construction that gives a 'congruent operation to the various components of the whole': Wilkie v Gordian Runoff Ltd [2005] HCA 17; (2005) 221 CLR 522, 529 [16].
To understand the context in which this issue arises, it is necessary to touch upon the evidence of witnesses called by each party concerning the different stages of exploitation of a hydrocarbon resource. Dr Brand gave evidence on that point. The plaintiff also called Mr Phillip Allan Meier, a consultant with extensive experience in engineering, procurement and construction in relation to offshore gas projects. The defendant called Mr Vincent Santostefano, who has held various senior positions in relation to onshore and offshore hydrocarbon operations, and held various technical operation and managerial positions with Woodside Petroleum Limited (Woodside), an offshore gas producer, between 1997 and 2013.
Each of the witnesses addressed the question as to what is understood within the oil and gas industry by the expressions 'development' and 'production'. There was little in the way of dispute between them.
Counsel for the plaintiff, in addressing the question of the use to be made of the evidence of the experts, drew attention to various authorities to the effect that, in construing a contract, contextual surrounding circumstances (that is events, circumstances and things external to the contract which are known to the parties) may be considered if the language of the contract is susceptible to more than one meaning or because there is a 'constructional choice': Mount Bruce Mining Pty Ltd v Wright Prospecting Pty Ltd [2015] HCA 37; (2015) 89 ALJR 990, 998 [47] ‑ [49]. There was no issue between the parties as to the admissibility of the evidence of the industry experts. Nor was there any issue as to their evidence that the expression 'development' and 'production' have commonly accepted meanings within the oil and gas industry. I accept that those terms in the JOA should be construed by reference to what a person in that industry would understand those terms to mean, and that the evidence of the experts was admissible for that purpose. As will be seen, I do not consider, however, that the meanings of the expressions 'development' and 'production' are determinative of the first issue.
Dr Brand said that he, and others in the industry, would understand the type of work undertaken when using 'terminology to describe the various phases of an offshore oil and gas project'. That terminology was:
(a)exploration and appraisal;
(b)development (which includes redevelopments that may occur after production has started);
(c)production; and
(d)abandonment.
Dr Brand gave an overview of an offshore project. He said that the first phase of an offshore project is the exploration and appraisal phase. Once it had been determined by the work during that phase that the volume of hydrocarbons is sufficient to meet a company's required minimum rate of return, or some other economic requirement, then the owners could justify moving forward to the next phase of the project.
He said that the next phrase of the project is the development phase. During that phase, the concept selection options for the asset are studied and analysed. Investment decisions are made and the project moves into actual engineering, procurement, construction and installation of the production platforms and, if part of the development concept, pipelines and onshore processing facilities.
After completion of the development phase, the project goes into the production phase and is turned over to production operations so that day‑to‑day operations in the field can be managed and the field produced in a safe and efficient manner. He said that the major activities of petroleum production are to bring the fluid to the surface, separate the liquid and gas components, and remove impurities.
Dr Brand explained that after initial development had been completed and production had begun, there might be a need for new infrastructure and additional capital investment to further develop the field so as to extract additional hydrocarbons. He said:
[s]uch redevelopments may be for the drilling of additional wells, replacement of or installation of new offshore platforms, or installation of compression whether offshore or onshore just to identify a few possible redevelopment type projects. Often the project management structure and approach used in the development phase is also used in the redevelopment project. Phases of redevelopment may or may not be included in the original field development plan. The final phase of an offshore field's life is the decommissioning and abandonment of the facilities and wells.
Dr Brand continued:
The question of when a project falls into a particular classification as to whether it is a production project or a development project is fact dependent; however, there are certain indicia recognised throughout the industry that assist with determining the classification. In the case of a redevelopment project, the indicia are similar to those of a development project and include:
(a)whether there is a large capital expense on new infrastructure;
(b)the project management structure - whether there is a project team, including FEED (Front End Engineering and Design) and Pre‑FEED work;
(c)how the project is approved;
(d)the accounting treatment of the costs of the project; and
(e)the objective of the project.
The VICP project scope is comprised of pre‑FEED, FEED and engineering and procurement, fabrication, delivery, installation, hookup and commissioning. This process is indicative of a development project. The scope is comprised of both a brownfield and a greenfield component which is common terminology for development. A brownfield project is considered to be a development that has a previous development or facilities in place; the term greenfield is used to describe a development to reference a site that has not been used (eg green or new) where a development can start without the need to consider any prior work or facilities.
Mr Santostefano's report which was tendered by the defendant addressed different questions from those posed to Dr Brand. Mr Santostefano directed his report to a consideration of the terms of the JOA and his opinion as to which budgeting approach would best suit the VICP under the JOA. That being a question of the proper construction of the JOA, a matter upon which Mr Santostefano was unqualified to express an opinion, and a matter for the court's determination, Apache Northwest placed little if any reliance on that aspect of Mr Santostefano's report at the hearing. Dr Brand and Mr Santostefano did, however, confer in relation to matters which were within their industry experience.
It was not in issue between the witnesses, nor between the parties, that generally speaking the stages of exploration, appraisal, development, production and abandonment generally occur in that temporal sequence. Mr Santostefano and Dr Brand agreed that once the production phase is reached, any project thereafter is not automatically a production project and could be characterised as a developmental project. They agreed that how one might characterise a particular project happening during the production phase (being the period commencing with the first production through until abandonment) may depend on various factors. Those factors include whether the project involves substantial capital expenditure, the way in which the project is dealt with internally by the organisation carrying it out, the way that organisation manages the asset, and the general objectives of the particular project.
Mr Meier agreed that the life cycle of a resource project involved the stages outlined above. His evidence drew upon his experience within the organisational structure of Woodside. He said that 'development' work could, and did in his experience, occur after production had been commenced. His experience where that occurred had resulted in such projects being treated internally by Woodside as 'development' rather than 'production' matters.
While the evidence of those witnesses identifies the industry context in which the JOA operates and in that sense assists in construing the JOA, it does not by itself determine the construction to be given to Articles VII and VIII of the JOA.
In relation to the first issue, the point of difference between the parties was whether, as the plaintiff contended, any work which might be characterised as 'development' could only be undertaken utilising the provisions of Article VII of the JOA, regardless of when the project was undertaken, or whether, as Apache contended, Article VII applied to the development phase in a temporal sense and Article VIII applied to work done and expenses incurred in the production phase (again in a temporal sense). In my view, the construction contended for by Apache is to be preferred.
The structure of the JOA, in particular Articles VI, VII and VIII, accords with what was described by the witnesses as the usual sequence of exploitation of a gas resource. It was not in issue that those phases of exploitation may each take a number of years before the next phase commences.
Article VI deals with exploration and appraisal Programmes and Budgets. Section 6.01 requires a current proposed exploration Programme and Budget for the next year to be submitted to the parties 'in each year'. That is a reference, necessarily, to each year in which exploration is being undertaken. There could be no commercial efficacy in requiring an exploration Programme and Budget to be submitted each year after exploration was completed. The exploration Programme and Budget must include, amongst other things, 'the projects and other works' necessary to satisfy the minimum works required by the relevant permit. Section 6.03 requires an annual review of an exploration Programme and Budget, and of an appraisal Programme and Budget. Section 6.06 enables a party to propose amendment to an approved exploration or appraisal Programme 'at any time'. In relation to any particular discovery, reference to 'any time' must, in order to give sensible meaning to the JOA, be a reference to 'any time' within the period that the Programme and Budget is operable. There could be no reason to amend an exploration or appraisal Programme after the Programme was completed and had served its purpose.
Once appraisal is complete, then Article VII becomes applicable. Section 7.01 obliges the Operating Committee to determine whether a discovery which has been the subject of an appraisal Programme has resulted in the delineation of petroleum in commercial quantities, and enables the Operating Committee to decide whether to instruct the Operator to commence the preparation of a development Programme in respect of the discovery. Section 7.02(a) requires that the development plan and budget for the discovery include, amongst other things, 'the projects and other work to be undertaken'.
In the event that the parties to the JOA do not unanimously decide to participate in the development, the provisions relating to sole risk development found in Article XI come into play. Section 11.02(i) provides for the identification of blocks which constitute a sub‑area in respect of which the relevant sole risk development is to apply. By s 11.03(i), a party which does not participate in the development of a discovery has no further rights in respect of that sub‑area. Those provisions support a construction of Article VII that it is designed to provide a mechanism by which, following appraisal, a discovery is to be developed and to specify the respective liabilities of the parties for the cost of development.

Like s 6.06 relating to exploration and appraisal Programmes and Budgets, s 7.03 provides for review and amendment of an approved development Programme and Budget. Like s 6.06, s 7.03(b) provides that amendment may be made 'at any time'. In my view, that is, as Apache contended, to be read as 'at any time during the budget period'. The budget period may, of course, extend over several years. Where, as in this case, a number of years after the approved development Programme and Budget have been completed, a proposal is made for works that can be characterised as 'development', it would be a strange mechanism to require approval of the Operating Committee to be obtained through the mechanism of Article VII. That is because Article VII is directed to making a decision as to participation in the discovery, and cannot readily be applied when that decision has already been made years earlier. The fact that sole risk development becomes available when Article VII is utilised does not assist the plaintiff's construction. It is difficult to see how s 11.03(i) would operate in those circumstances. It would be inconsistent with the commercial purpose of the agreement for the non‑participating party to be deprived of rights in respect of the relevant sub‑area which it had been enjoying since its original decision to participate in the development of the discovery. In this case, Santos' decision to participate in the John Brookes discovery was made following presentation to the Operating Committee of the development Programme and Budget approved in October 2003. Inherent in that approval was a decision by the parties to undertake the liability to contribute their percentage interests in future costs subject to approval of the Operating Committee of future programmes and budgets and the regime for that approval under s 8.01(b) of the JOA. The possible expense of inlet compression, although not quantified, was clearly contemplated as a possibility by the development Programme and Budget.
The proposition that Article VII is designed to regulate the position of the parties between the completion of appraisal and the commencement of production is supported by the reference in s 7.03(c) to the potential necessity for parties to meet together to consider whether the JOA may be found wanting 'at the development phase'. Santos contends that those words should be read as meaning, in effect, 'in relation to development'. I do not accept that contention. The use of the expression 'development phase', and in s 8.03 the expression 'production phase', is consistent with the construction that Articles VI, VII and VIII are directed to the temporal phases of exploration and appraisal, development and production respectively.
Article VIII deals with production Programmes and Budgets. Section 8.01(a) requires the preparation of an annual Programme and Budget in the year prior to that in which production commences, and then each subsequent year. It is clear that production Programmes and Budgets are referrable to the time during which production is undertaken. Section 8.01(a)(i) requires that the production Programmes and Budget include, amongst other things, 'the projects and other work to be undertaken'. That is the same expression as is used in relation to the contents of both exploration and appraisal Programmes and Budgets and development Programmes and Budgets. The use of those same expressions in relation to each type of programme and budget suggests that a particular programme and budget is to be directed to the work to be undertaken, however it might be characterised, during the different temporal phases. That is, they are directed to whatever expenditure is proposed to be incurred during the relevant phase. The contention made by Santos requires that 'projects' be read as 'exploration projects', 'development projects' or 'production projects', in Articles VI, VII and VIII respectively. Within the context of the JOA, I see no basis to provide that gloss to the plain words of the provisions.
In my view, on the proper construction of the JOA, notwithstanding that the VICP might be categorised as a development project as that expression is commonly understood in the industry, it is capable of being the subject of a production Programme and Budget pursuant to Article VIII of the JOA.

Issue 2 - Inclusion of previous expenditure in a programme and budget

Santos pleads that, on the proper construction of the JOA, neither a participant nor the Operator can include in either a development Programme and Budget, or a production Programme and Budget, expenditure already incurred without the prior approval of the Operating Committee unless such expenditure was otherwise specifically authorised by the terms of the JOA. That contention is based upon the contention that no participant or the Operator can take any material step or incur any expenditure with respect to the development or production of gas from the John Brookes production licence unless the step is taken with the prior approval of the Operating Committee as part of the joint operation, or the expenditure has been approved by the Operating Committee, or the step is taken or the expenditure is incurred as a result of a sole risk development permitted by Article XI of the JOA. The contention is also based on the proposition that the prospective language used in Articles VII and VIII supports the construction contended for.
As to the first proposition, reliance is placed on s 2.03, which requires a party not to 'conduct any operation under, or exercise any rights conferred by, a joint licence'. To consider the application of that prohibition, it is necessary to identify operations under, or rights conferred by, the relevant joint licence.
The relevant joint licence in relation to the John Brookes oil field is WA‑29‑L, which was granted on 21 December 2004. WA‑29‑L was issued pursuant to the PSL Act. Upon repeal of that Act, by reason of the transitional provisions found in sch 6 of the OPGGS Act, the licence remained in force subject to the provisions of the OPGGS Act. Section 161(1) of the OPGGS Act provides:
(1)A petroleum production licence authorises the licensee, in accordance with the conditions (if any) to which the licence is subject:
(a)to recover petroleum in the licence area; and
(b)to recover petroleum from the licence area in another area to which the licensee has lawful access for that purpose; and
(c)to explore for petroleum in the licence area; and
(d)to carry on such operations, and execute such works, in the licence area as are necessary for those purposes.
That section substantially reflects the provisions of s 52 of the PSL Act, which specified the rights conferred by a licence under that Act.
The question for present purposes is whether the incurring by Apache of expenditure on its own account in relation to the VICP comprised an operation under, or the exercise of rights conferred by, WA‑29‑L. In my view, it did not.
The precise capacity in which initial works relating to the VICP were undertaken within the Apache Group is by no means clear. As noted above, and as is common ground on the pleadings, in May 2012, Apache Energy, on behalf of the East Spar Apache participants, sought the approval of the East Spar Joint Venture Operating Committee for FEED studies, and, on Santos' rejection of that proposal, foreshadowed undertaking the work on a 'sole risk basis' under the terms of the East Spar Joint Venture Operating Agreement. The relationship of the VICP to the East Spar Joint Venture was not a matter explored in any detail in the evidence. All that can be deduced from that somewhat confusing evidence is that Apache Energy was anxious to be in a position where the compression project could proceed in a timely way if and when the project was adopted as a Joint Operation of whichever joint venture was relevant. Notwithstanding that confusion, Apache Northwest accepts that the VICP would facilitate the maintenance and extension of production from the John Brookes field and allow for the recovery of additional gas, and that the steps taken to progress the VICP by Apache Energy were undertaken at the instance of Apache Northwest. Those steps did not, however, require the authority of the joint licence. Ultimate implementation of the VICP, and preparation for and construction of plant and equipment, did not involve the recovery of petroleum, notwithstanding that the plant and equipment might ultimately, pursuant to the requisite approvals under the JOA, be utilised for that purpose.
In my view, s 2.03 of the JOA does not preclude Apache Northwest from permitting or procuring Apache Energy to take the steps referred to in [26] of the statement of claim.
Nor do I consider that those steps amounted to joint operations for the purposes of the JOA, with the consequence that Apache Northwest as Operator could only undertake them with the approval of the Operating Committee. Steps were undertaken at the expense and risk of the Apache Group. The Operating Committee has the exercise of overall supervision and control of matters pertaining to 'Joint Operations' (s 5.01). The steps taken were not Joint Operations under the agreement.
Santos' second proposition is that the use of prospective language in Articles VII and VIII requires the construction that past expenditure cannot be included in a development Programme and Budget or a production Programme and Budget.
Reliance is placed on the expression a 'proposed development Programme and Budget' in s 7.02(a) and s 7.02(b), and a 'proposed production Programme and Budget for the next year' in s 8.01(a) and s 8.01(b). I agree with Apache Northwest's submission that the word 'proposed' is directed to the 'budget'. That is, it is the budget being proposed for approval. The words do not, in my view, exclude the inclusion in the budget of expenses that a participant may have already met but which are proposed as part of a proposed joint operation. Support for that construction can be found in the accounting procedure contained in Appendix B to the JOA. Clause 3.5, which is set out above, contemplates the sale by a party of fixed assets which it owns to the joint venture for the purpose of joint operations. The sale is to take place at fair market value. For that provision to be operative, the selling party must necessarily have incurred the expense of acquisition of the asset. To give effect to that provision, Articles VII and VIII must be construed as enabling a party which proposes the sale of an existing fixed asset to the JOA parties to have the expenses relating to the sale of that asset included in a proposed budget. That is, in effect, what has happened in this case.
On its proper construction, the JOA does not preclude past expenditure from inclusion in a proposed programme and budget.
That conclusion is unaffected by the use of the words 'projects and other work to be undertaken' in both s 7.02(a) and s 8.01(a). Those matters are required to be included in a programme and budget, but the programme and budget is not 'limited to' those and the other matters referred to in each section. There is no reason why a proposed budget should not include expenditure which does not arise by reason of 'work to be undertaken'.

Issue 3 - Did Apache Northwest breach the JOA?

Santos asserted the following breaches of the JOA:
(i)Breach of the prohibition against taking any material step with respect to the development or production of gas from WA‑29‑L unless the step is taken with Operating Committee approval, by progressing the VICP without prior approval of the Operating Committee.
(ii)Breach of the obligation not to incur expenditure on development or production unless approved by the Operating Committee or as a sole risk development, by progressing the VICP without such approval and other than as a sole risk development under the JOA.
(iii)Breach of an obligation not to include in a development Programme or Budget or a production Programme and Budget expenditure already incurred without prior approval of the Operating Committee, by including in the 2014 AWPB expenditure that had already been incurred.
Santos' allegations of breach of the JOA are based upon acceptance of the construction for which it contended in relation to issues 1 and 2. The claims of breach fall away by reason of the conclusions which I have reached on those issues.

Issue 4 - Remedies

The parties at trial agreed that the issues between them as to the appropriate remedies should not be dealt with until such time as the questions of construction were resolved. Given my conclusions as to the issues of construction, no question of remedies arises. The consequence of my conclusions is that the action should be dismissed.