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 AMENDMENT TO PRODUCTION SHARING CONTRACT





JPDA 03-12





This amendment to production sharing contract 03-12 which has been approved by the Joint


Commission established under the Timor Sea Treaty (hereinafter called the Treaty), is made and


entered into on this 16 day of May 2003 by and between the Designated Authority established


under the Treaty, party of the first part, and ConocoPhillips (91-12) Pty Ltd ABN 73 064 963


346, a corporation organised and existing under the laws of Australia, Santos (JPDA 91-12) Pty


Ltd ABN 44 056 937 752, a corporation organised and existing under the laws of Australia,


INPEX Sahul, Ltd ARBN 059 844 781, a corporation organised and existing under the laws of


Japan, Petroz (Timor Sea) Pty Ltd ABN 85 053 698 794, a corporation organised and existing


under the laws of Australia and Emet Pty Ltd ABN 49 050 134 908, a corporation organised and


existing under the laws of Australia hereinafter collectively called the “contractor”, parties of the


second part, both hereinafter sometimes referred to either individually as the “Party” or


collectively as the “Parties”.


WITNESSETH


The attachment hereto entitled Appendix X to Production Sharing Contract 03-12is hereby


attached to and made a part of fire said production sharing contract as Appendix X. The


production sharing contract is amended as provided therein with effect on and from the date on


which the amendment to the Bayu-Undan development plan is approved by the Designated


Authority and shall thereafter continue in full force and effect as so amended. This amendment


shall not invalidate any action taken in accordance with the production sharing contract before


such date.








IN WITNESS WHEREOF, the Parties hereto have executed this contract, in six original copies


and in the English language, on this 16 day of May, 2003.














THE DESIGNATED AUTHORITY




















BY
































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CONOCOPHILLIPS (91-12) PTY LTD ABN 73 064 963 346









































SANTOS (JPDA 91-12) PTY LTD ABN 44 056 937 752












































INPEX SAHUL, LTD ARBN 059 844 781












































PETROZ (TIMOR SEA) PTY LTD ABN 85 053 698 794






























































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EMET PTY LTD ABN 49 050134 908
































APPROVED BY THE JOINT COMMISSION on this 16 day of May 2003

















•/L BY UDJL^


BY


A ^&


JOINT COMMISSIONER JOINT COMMISSIONER


FOR TIMOR-LESTE FOR AUSTRALIA








&














jointCommissioner


FOR^PIMO^ESTE















































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 APPENDIX X





TO PRODUCTION SHARING CONTRACT JPDA 03-12











In this Appendix,


'Approved contract' means a contract made by the contractor and approved by the Designated


Authority as a part of the development plan;


'Bayu-Undan discovery area' means the area so approved on 17 December 2001, as amended


from time to time;


’Downstream facilities' means facilities downstream of the field export point for transporting,


processing, liquefying, storing, handling and delivering natural gas produced from the Bayu-


Undan discovery area, whether in gaseous or liquid form; and


'Field export point1 means the natural gas export flange in the Joint Petroleum Development


Area, as identified in the development plan;


and, unless otherwise specified, reference to a Section is to a Section of the main body of this


contract. Sections 2, 3,4 and 5 of this Appendix shall have effect only on and from the approval


by the Designated Authority of an amendment to the development plan providing for the export


of natural gas from the Bayu-Undan discovery area by the export pipeline and its liquefaction in


the LNG plant (both as defined in Section 3 of this Appendix).


The provisions of this Appendix shall be deemed to form part of this contract and Directions,


Regulations and Administrative Guidelines issued under the Petroleum Mining Code shall apply


to the provisions of this Appendix to the same extent that they apply to this contract and, where


appropriate, references within Directions, Regulations and Administrative Guidelines to


provisions of the contract shall be read to include the relevant provisions of Appendix X.





SECTION 1


FUNDING PLAN AND AMENDMENT TO BAYU-UNDAN DEVELOPMENT PLAN


1.1 This Section shall apply only to the Bayu-Undan discovery area.


1.2 The contractor shall not sell natural gas other than under an approved contract and shall


not otherwise dispose of natural gas other than as provided in the development plan. The


contractor shall not use downstream facilities other than under an approved contract


1.3 Any proposal by the contractor to amend the development plan to provide for the sale by


the contractor of natural gas at or downstream of the field export point (or to further amend the


development plan in that regard) shall include (to the extent not previously submitted and, if


necessary, approved), but is not limited to:











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(a) details of:


(i) all contracts made by the contractor for the sale of that natural gas,


whether in gaseous or liquid form (together with copies thereof);


(ii) (for information purposes only) all contracts made by persons in respect


of that natural gas, whether in gaseous or liquid form, downstream of the


point at which that natural gas is to be sold by the contractor and which


are relevant to the price at which such natural gas is to be sold by the


contractor or would otherwise be relevant to the determination of the


value of that natural gas pursuant to Section 3 of this Appendix, but not


beyond the point of sale under the first arm's length transaction for sale


of that natural gas (together with copies thereof except to the extent the


Designated Authority otherwise agrees);


(iii) (for information purposes only) all downstream facilities the costs of


which are relevant to the price at which such natural gas is to be sold by


the contractor or would otherwise be relevant to the determination of the


value of that natural gas pursuant to Section 3 of this Appendix, but not


beyond the point of sale under the first arm's length transaction for sale


of that natural gas; and


(iv) all contracts made by the contractor in respect of those downstream


facilities (together with copies thereof; except to the extent the


Designated Authority otherwise agrees);


(b) an environmental management plan covering the life of the project, and a plan for


securing the safety, health and welfare of persons engaged in petroleum


activities, on or about the Joint Petroleum Development Area;


(c) the expected year of decommissioning and an outline decommissioning plan


addressing the issues mentioned in Section 2 of this Appendix; and


(d) the calculation of the economics to show the commerciality of the amendment


and of the development plan as proposed to be amended;


1-4 Concurrent with any proposal to amend the development plan, and except to the extent


previously submitted and approved, each individual contractor party shall submit for approval by


the Designated Authority a funding plan which identifies its sources of funds for petroleum


activities, and such shall not be amended without the approval of the Designated Authority. The


Designated Authority shall not approve an amendment to file development plan unless it has


approved a funding plan for each individual contractor. Funds shall only be sourced in accordance


with an approved funding plan. If an individual contractor party (defaulting contractor) foils to


comply with the foregoing provisions of this subsection 4:


(a) it shall not be entitled to the benefit of the amendments to this contract


introduced by subsection 5 of Section 2, subsection 5 of Section 4 and subsection


8 of Section 4 of this Appendix; and


(b) the share of petroleum to which the Designated Authority is entitled shall be


increased by such quantity as would have accrued to the defaulting contractor as





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a consequence of such subsections and by reference to its undivided participating


interest but for this subsection 4;


but (unless all the individual contractor parties so fail to comply) such failure shall not otherwise


be a breach of this contract by the contractor. For the purposes of the foregoing, "undivided


participating interest" means the interest of the individual contractor party concerned as identified


in the Register of Contractors maintained under Article 38 of the Petroleum Mining Code.





SECTION 2


BAYU-UNDAN DECOMMISSIONING PLAN AND COST RESERVE


2.1 This Section shall apply only to the Bayu-Undan discovery area.


2.2 Not later than 30 September 2007, the contract operator shall submit to the Designated


Authority, for its approval, a decommissioning plan for the Bayu-Undan discovery area which


shall include, but is not limited to:


(a) measures to be taken to effect decommissioning in compliance with applicable


law, this contract and standards generally recognised from time to time as


applicable in the international petroleum industry, including but not limited to:


(i) decommissioning equipment and installations in the Joint Petroleum


Development Area;


(ii) other steps reasonably required to prevent hazard to human life, to the


property of others or to the environment; and


(iii) environmental, engineering and feasibility studies reasonably necessary


to support the plan; and


(b) estimates of the costs and time required to complete activities under the plan, and


a schedule of provisions for the purposes of the decommissioning costs reserve


(as mentioned in subsection 5 of this Section).


2.3 The decommissioning plan shall be revised and resubmitted to the Designated Authority


for its approval at such times as are reasonable having regard to the likelihood that the plan and/or


the cost estimates therefor may need material revision.


2.4 The contractor shall carry out the decommissioning plan substantially in accordance with


its terms.


2.5 A decommissioning costs reserve shall be cost recoverable by the contractor in each of


the fifteen (15) years beginning 1 January, 2008 ('decommissioning reserve period').


2.6 The decommissioning costs reserve shall be calculated by reference to the total


decommissioning costs approved by the Designated Authority pursuant to subsection 2 of this


Section from time to time. The decommissioning costs reserve for a year shall be determined by


the formula:








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DCR = (A/(A+B))RDC, where


DCR is the decommissioning costs reserve for the year concerned


A is (by reference to the first development plan amendment) the quantity of liquid


petroleum gas and condensate forecast to be produced from die Bayu-Undan discovery


area in the year concerned


B is (by reference to the first development plan amendment) the forecast reserves of


liquid petroleum gas and condensate still to be produced from die Bayu-Undan discovery


area, in the decommissioning reserve period, at the end of that year


RDC is the remaining decommissioning costs yet to be recovered at the start of the year


in question, assuming the total cost estimates from the latest approved decommissioning


plan.


2.7 If the above formula results in a negative amount, then such amount shall be treated as a


reduction of recoverable costs for the year in question.


2.8 The contractor shall comply with, enforce and not without the approval of the Designated


Authority amend Article 20.7 or Exhibit G of the unit operating agreement, nor shall the


contractor amend the percentage value mentioned in Article 20.4 thereof agree an alternative


Rundown Period Commencement Date or make any decision (inducting through the Unit


Operating Committee) as is referred to in Exhibit G thereof and which would prejudice the value


of the rights granted the Designated Authority under subsection 9 of this Section, without the


approval of the Designated Authority. Copies of all Guarantees and Trust Deeds as mentioned in


Exhibit G will be promptly provided when executed to the Designated Authority. The contractor


shall promptly advise the Designated Authority if a party to the unit operating agreement finis to


provide or maintain a required Security (and of all material communications thereafter in relation


thereto).


2.9 The contractor agrees (and any Guarantee or Trust Deed shall provide) that the


Designated Authority will be a beneficiary of any Security as mentioned in Article 20.7.1 of the


unit operating agreement and shall be entitled to enforce the Security in accordance with that


Article if the other beneficiaries decline to do so after a request from the Designated Authority.


2.10 If any individual contractor party (defaulting contractor) fails to comply with the


provisions of subsections 8 and 9 of this Section, the defaulting contractor shall be a Defaulting


Party pursuant to Article 20.7 of the unit operating agreement but such shall not be a breach of


this contract by the contractor if the other individual contractor parties (and if and for so long as


the other individual contractor parties are diligently seeking to) enforce the provisions of Article


20.7.1 of the unit operating agreement against that defaulting contractor.


2.11 For the purposes of subsections 8, 9 and 10 of this Section, 'unit operating agreement’


means the agreement entitled Unit Operating Agreement for the Bayu-Undan Field executed on


14 July 1999 with effect from 1 April 1999, and all words and expressions defined therein shall


have the same meaning when used in those subsections.














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 SECTION 3





BAYU-UNDAN NATURAL GAS VALUATION


3.1 This Section shall apply only to natural gas produced and saved from the Bayu-Undan


discovery area and not used in field activities. In this Section:


'Calculation period’ means a period beginning 1 January 2002 and ending at the end of


the calendar year in which occurs the sixteenth (la ) anniversary of the date of


commencement of regular downstream deliveries.


'Capacity reservation charge' means, in respect of a month and, separately in respect of


each of the export pipeline and the LNG plant (each a 'facility'), an amount given by the


formula:


CRC = CC/12, where


CRC is the capacity reservation charge for a month, and


CC is given by the formula:


NCF = CC---(C+D+E), where


NCF is tiie net cash flow in a year of the calculation period


C, in the twelve (12) months after the fifteenth (15*) anniversary


of the date of commencement of regular downstream deliveries,


is the estimated costs of decommissioning the facility, assuming


an inflation rate of two decimal five (2.5) per cent per annum


from the date of the estimate, and otherwise is zero


D is the capital costs (being expenditures made for items which


normally have a useful life of more than one (1) year) incurred


by the owners of the facility in the year of the calculation period


for which NCF is being calculated (including, but not limited to,


feasibility and engineering costs and other costs incurred for the


purposes of designing and constructing the facility (and in the


first year, those costs incurred prior to the start of the calculation


period)), but only to the extent such are incurred in respect of the


facility before the date of commencement of regular downstream


deliveries


E is the estimated aggregate income tax payments payable by the


owners of the facility to the Commonwealth of Australia in the


year of the calculation period for which NCF is being calculated,


assuming an income tax rate of thirty (30) per cent and a fifteen


(15) year depreciation life, and otherwise in accordance with


applicable law and its application as at the date of entry into


force of the Treaty, and further assuming that the owners are


special purpose vehicles having no other business, and








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 CC is the capacity charge for each year of the calculation period


in which downstream deliveries occur, starting with the date of


commencement of regular downstream deliveries, and is


determined by iteration as follows:





NCF in each year of the calculation period is discounted


to the middle of the first year of the calculation period,


using a discount rate of eight (8) per cent and assuming


that NCF for each such year is received in the middle of


that year. NCF for the first year of the calculation period


is not discounted


CC is escalated annually at a compounding rate of two


decimal five (2.5) per cent, but is zero in the twelve (12)


months after the fifteenth (15th) anniversary of the date


of commencement of regular downstream deliveries, and


CC in the first year is that amount which, if applied in


the determination of NCF in that first year, and if that


amount escalated annually at a compounding rate of two


decimal five (2.5) per cent were the factor CC applied in


the calculation of NCF in subsequent years of the


calculation period (except in the twelve (12) months


after the fifteenth (15th) anniversary of the date of


commencement of regular downstream deliveries, when


CC is zero), would result in the sum of the NCFs


discounted at eight (8) per cent for the calculation period


being zero


The capacity reservation charge in respect of each facility and for each year:


(a) shall be calculated at (and all estimates required therefor shall be calculated as at)


the date of commencement of regular downstream deliveries and will not


thereafter be changed; and


(b) shall be calculated in United States dollars, costs in other currencies being





translated to United States dollars as mentioned elsewhere in this contract


For the purposes of illustration, examples of calculations of the capacity reservation


charge are [file location to be identified].


'Date of commencement of regular downstream deliveries' means the first day after


commissioning of both the export pipeline and the LNG plant is completed and they are


ready both to take delivery of natural gas for transport and for commercial production of


liquefied natural gas.


'Downstream operating costs’ means, in respect of a month and separately in respect of


each of the export pipeline and the LNG plant (each a 'facility'), an amount equal to the


actual operating costs (including taxes other than taxes on income, profit or gain and


further including expenditures to maintain, repair and replace equipment necessary for


the operation of the facility) incurred by the owners of the facility in that month, but only





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 to the extent such are incurred on and from the date of commencement of regular


downstream deliveries in respect of the facility, but does not include:


(a) any cost or provision against the eventual costs of decommissioning the export





pipeline, the LNG plant or other downstream facilities if such costs or provisions


have been included in the calculation of the capacity reservation charge;


(b) depreciation of capital costs; and





(c) the cost of natural gas used within the LNG plant;


but does include any cost (including, but not limited to, arising from an underprovision in


the calculation of the capacity reservation charge), credit (including, but not limited to,


arising from an overprovision in the calculation of the capacity reservation charge) or


provision against the eventual costs of decommissioning the export pipeline, the LNG


plant or other downstream facilities but not to the extent any such cost or provision has


been included in the calculation of the capacity reservation charge.


'Export cost charge' means





(a) separately in respect of each of the export pipeline and the LNG plant, and in


respect of each calendar month of the period beginning on the first day of the


calendar month immediately after the date of commencement of regular


downstream deliveries and ending fifteen (15) years later, the aggregate of the


capacity reservation charge and the downstream operating costs provided that in


the first such calendar month the downstream operating costs shall include the


downstream operating costs incurred by the owners of the facility in the


preceding calendar month;





(b) separately in respect of each of the export pipeline and the LNG plant, and in


respect of each calendar month after the period mentioned in paragraph (a)


above, the tariff; and





(c) in respect of other downstream facilities, the costs incurred by the contractor in


respect thereof.


Notwithstanding anything to the contrary contained in this contract, interest or any


payment in the nature of or in lieu of interest, or borrowing costs shall not be allowed in


the computation of the export cost charge.


The export cost charge shall be payable calendar monthly in arrears.


'Export pipeline' means the pipeline from the field export point as identified in the


development plan.


TiNG plant1 means the liquefied natural gas plant as identified in the development plan.





Tariff' means, in respect of a month and separately in respect of each of


the export pipeline and the LNG plant ,an amount agreed by the


contractor and the respective owners thereof, and approved by the


Designated Authority, or, failing such agreement or approval, an amount





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determined by an expert, all in the manner and subject as provided in the


approved contract concerned.


3.2 Natural gas shall be valued at the field export point


3.3 The value of natural gas sold by the contractor at the field export point shall be the price


received by the contractor therefor under five approved contract


3.4 In any month, the value of other natural gas sold by the contractor and transported by the


export pipeline shall be determined by a net back mechanism as follows:


(a) the price received by the contractor therefor under approved contracts; less


(b) the aggregate of so much of:


(i) the export cost charge in respect of the export pipeline; and


(ii) the export cost charge in respect of the LNG plant; and


(iii) the export cost charge in respect of other downstream facilities;


as is paid that month (and net of credits) by the contractor under approved


contracts; less


(c) any carried forward export cost charge; plus


(d) except to the extent taken into account in paragraph (a) of this subsection 4, all


amounts paid by the purchasers of natural gas or the owners of those downstream


facilities to the contractor in respect of the sale of that natural gas or the use of


those facilities.


3.5 In determining the value of natural gas and unless the Designated Authority otherwise


agrees, no account shall be taken of any reduction in the price received by the contractor for the


sale of natural gas under an approved contract or otherwise any reduction in the value of natural


gas, which is the result of the waiver by any person of or the failure by any person to enforce,


any provision of any approved contract


3.6 If the value of natural gas determined in accordance with subsection 4 of this Section 3


results in a value of less than zero, during any year prior to the period of plateau production, then


the value for that month shall be deemed to be zero, and that portion of the export cost charge


which otherwise would result in the value of natural gas being less than zero shall be carried


forward and treated as a deduction in determining the value of natural gas in the next month, and


shall be referred to as the carried forward export cost charge.


3.7 Any carried forward export cost charge shall be escalated at a nominal rate of eight (8)


per cent per annum.


3.8 The contractor shall procure for the Designated Authority audit and information rights


from the owners of the downstream facilities, and from their respective affiliates, equivalent to


those which it has in and in respect of this contract in order to verify the value of natural gas for


the purposes of this Section. For the purposes of this subsection, 'affiliate* shall have the same





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meaning in regard to any such owner as it would have if it were a party to this contract, mutatis


mutandis, and shall additionally include any corporation or other entity which is under common


control with any such owner.


3.9 The contract operator shall provide a monthly gas valuation return in a form to be


approved by the Designated Authority prior to the date of commencement of regular downstream


deliveries. Such return shall provide sufficient detail to allow the Designated Authority to verify


the application of the provisions of this Section 3 and shall be the basis for the Designated


Authority's audit under subsection 8 of this Section.


3.10 If any downstream facilities are designed and / or built to be of a greater capacity than is


required for natural gas produced from the Bayu-Undan discovery area and with the intent that


they be used for natural gas from other than the Bayu-Undan discovery area, only such portion of


the costs thereof as is so required shall be allowed.


3.11 Subject only to subsections 10 and 12 of this Section, the capacity of foe downstream


facilities shall be reserved by the contractor and, to the extent that that capacity is used for natural


gas from other than foe Bayu-Undan discovery area and the benefit thereof accrues to the


contractor, that benefit will be added to the value of natural gas under subsection 4 of this


Section. If such use is not pursuant to an arm's length transaction, foe benefit shall be deemed to


be that which would have so accrued to the contractor had it so been.


3.12 For all purposes of this Section, costs shall not be greater than those that are for the


necessary and proper conduct of the construction and operation of the downstream facilities and


incurred in accordance with generally accepted accounting principles and practices of the


international petroleum industry recognising that for accounting purposes the inclusion in


downstream operating costs of expenditures necessary to maintain, repair and replace the


equipment necessary for the operation of the downstream facilities may be inconsistent with such


principles and practices. Where property or any other thing for which a cost is allowable under


this Section is only used (or any cost is only incurred) partially in respect of natural gas, whether


in gaseous or liquid form, produced from the Bayu-Undan discovery area, only that proportion of


the cost which relates to that natural gas shall be allowed.


3.13 If the buyer under any approved contract for foe sale of natural gas, whether in gaseous or


liquid form, is obliged to pay for quantities not taken, the quantities in respect of which such


payment is made shall be deemed to have been produced and delivered to foe buyer when that


payment is made.


3.14 Any costs associated with either the payment or production of natural gas in subsection


13 of this Section 3 shall be deemed to be:


(a) operating costs if such costs are incurred before the field export point; and


(b) downstream operating costs, if such costs are incurred beyond the field export


point;


only when such costs are incurred.


3.15 If the approved contract requires the contractor to deliver the quantities not taken (as


mentioned in subsection 13 of this Section) at a later date and the approved contract requires an


adjustment to the price at such later date, then that adjustment amount, and only that adjustment





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amount, shall be included in the value of natural gas determined in accordance this Section 3, at


such later date.


3.16 In regard to that approved contract entitled Feed Gas Sale and Purchase Agreement


between the contractor and the owner of the LNG plant:


(a) if the Buyer (as therein defined) fails to pay an amount due and payable by it to


the Sellers (as therein defined), the Sellers shall be deemed to have received such


amount, provided that, in the case of back to back receipts, these have been paid


to or as directed by the Buyer. For the purpose of this paragraph, "back to back


receipts" means amounts due to the Buyer that directly relate to amounts payable


to the Sellers, including amounts under the LNG HOA or the LNG Sale and


Purchase Agreement (both as therein defined); and


(b) risk in the Designated Authority's share of natural gas from the Bayu-Undan


discovery area shall pass to the contractor at the field export point.


Any amount deemed received as mentioned above shall not again be considered a receipt if and


when actually received.


3.17 If any provision of an approved contract provides for a matter to be resolved by a process


which involves the participation of the Designated Authority, the matter shall not be resolved


other than in accordance with that process and the Designated Authority and the contractor shall


be bound by the outcome thereof.








SECTION 4


MISCELLANEOUS AMENDMENTS


In this Section, and for convenience only, the amendments introduced to this contract are in


italics.


4.1 There is added to subsection 3 of Section 1:





"Appendix X" means the appendix marked X attached to and made a part of this contract


4.2 Subsection 5 of Section 5 is deleted and the following substituted:





"5.5 The Designated Authority shall comply with all of the obligations imposed on it


by the Treaty, including the Petroleum Mining Code and, in particular, shall be


responsible for the management of the petroleum activities contemplated hereunder


having regard to the contract operator's responsibilities for undertaking petroleum


activities and in complying with such obligations shall act reasonably


4.3 Subsection 3 of Section 6 is deleted and the following substituted:


"6.3 'Operating costs' means the sum of the following costs incurred in petroleum


activities undertaken before or at the point of tanker loading or, in the case of natural gas


from the Bayu-Undan discovery area, before or at the field export point as defined in


Appendix X'.





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 (a) current calendar year exploration costs;


(b) current calendar year non-capital costs;


(c) current calendar year depreciation of capital costs; and


(d) allowable operating costs incurred in previous calendar years which have not


been recovered in accordance with subsection 2 of Section 7 of this contract;


(e) the decommissioning costs reserve mentioned in Section 2 of Appendix X;





less


(f) miscellaneous receipts as defined in subsection 8 of this Section."


4.4 Subsection 8 of Section 6 is deleted and the following substituted:


”6.8 'Miscellaneous receipt* means the value of property defined in paragraph (c)





below and all monies received by the contractor, other than for the disposal of petroleum


produced from the contract area, which are directly related to the conduct of petroleum


activities in the contract area. Miscellaneous receipts include, but are not limited to, the


following:





(a) any amounts received from the sale or disposal of petroleum produced from


production testing activities undertaken in exploration and appraisal wells;


(b) any amounts received for the disposal, loss, or destruction of property the cost of


which is an operating cost;


(c) the value of property, the cost of which is an operating cost, when that property


ceases to be used in petroleum activities in the contract area;


(d) any amounts received by the contract operator under an insurance policy, the


premiums of which are operating costs, in respect of damage to or loss of


property;


(e) any amounts received as insurance, compensation or indemnity in respect of


petroleum production lost or destroyed prior to the point of tanker loading; or, in


the case of natural gas from the Bayu-Undan discovery area, at the field export


point as defined in Appendix X;


(f) any amounts received from the hiring or leasing of property, the cost of which is


an operating cost;


(g) any amounts received from supplying information obtained from surveys,


appraisals, or studies the cost of which is an operating cost;


(h) any amounts received as charges for the use of employee amenities, the cost of


which is an operating cost; and








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(i) any amounts received in respect of expenditures which are operating costs, by


way of indemnity or compensation for die incurring of the expenditure, refund of


the expenditure, or rebate, discount or commission in respect of the expenditure.”


4.5 Subsection 9 of Section 6 is deleted and the following substituted:


”6.9 The following expenditures are not eligible as operating costs:


(a) payments of principal or interest on a loan or other borrowing costs unless


approved by the Designated Authority under paragraph (c) of subsection 10 of


this Section;


(b) payments of interest components of credit-purchase payments;


(c) payments of dividends or the cost of issuing shares;


(d) repayments of equity capital;


(e) payments of private override royalties;


(f) payments associated with a farm-in agreement;


(g) payments of taxes under the taxation law of either Contracting State made in


accordance with Article 5 of the Treaty;


(h) payments of administrative accounting costs, and other costs indirectly associated


with petroleum activities in the contract area;


(i) costs incurred once petroleum production has passed the point of tanker loading


or, in the case of natural gas from the Bayu-Undan discovery area, the field


export point as defined in Appendix X;


0 costs incurred as a result of non-compliance by the contract operator with the


provisions of this contract, the Petroleum Mining Code or the regulations and


directions issued under the Petroleum Mining Code;


(k) unless otherwise approved by the Designated Authority, costs incurred by


contractors other than the contract operator;


(l) notwithstanding paragraph (g) of subsection 6 of Section 6, any decommissioning


costs actually incurred which have been taken into account for the purposes of


determining the provision under subsection 5 of Section 2 of Appendix X; and


(m) the export cost charge os defined in subsection 1 of Section 3 of Appendix X."


4.6 Subsection 5 of Section 7 is deleted and the following substituted:


”7.5 Of the amount of natural gas, including propane and butane fractions extracted


from natural gas but not spiked in crude oil, remaining after recovering investment credits


and operating costs associated with natural gas activities, the Designated Authority shall


be entitled to take and receive fifty (50) per cent and the contractor shall be entitled to





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take and receive fifty (50) per cent except in respect of natural gas (including such


fractions) produced from the Bayu-Undan discovery area, where the Designated


Authority shall be entitled to take and receive forty (40) per cent and the contractor shall


be entitled to take and receive sixty (60) per cent.”


4.7 Subsection 6 of Section 7 is deleted and the following substituted:


"7.6 Title to the contractor’s share of petroleum production under subsections 3, 5 and


9 of this Section as well as to the shares of petroleum production exported and sold to


recover investment credits and operating costs under subsections 10 and 2 of this Section


respectively shall pass to the contractor at the point of tanker loading or, in the case of


natural gas from the Bayu-Undan discovery area, at the field export point as defined in


Appendix X”


4.8 Subsection 8 of Section 7 is deleted and the following substituted:


"7.8 Any natural gas produced from the contract area and not used in petroleum


activities hereunder may be flared if the processing and utilisation of the natural gas is not


considered by the Parties to be economic. Such flaring shall be permitted to the extent


that gas is not required to enable the maximum economic recovery of petroleum by


secondary recovery activities, including repressuring and recycling. Notwithstanding the


foregoing, natural gas and LPG producedfrom the Bayu-Undan discovery area may only


be flared if this process is necessary to meet safety requirements or if necessary in the


short term for operational optimisation consistent with maximising economic recovery of


petroleum.”


4.9 Subsection 9 of Section 7 is deleted and the following substituted:


"7.9 Notwithstanding the other provisions of this Section, in the initial five (5)


calendar years of production from the contract area (such period to be determined without


regard to whether production commenced under this contract or the previous contract),


the Parties shall be entitled to take and receive a quantity of petroleum equal to ten (10)


per cent of the petroleum production in those years, called the 'first tranche petroleum',


before any recovery of investment credits and operating costs. In each subsequent


calendar year, the first tranche petroleum shall be equal to:


(a) in respect of petroleum from the Bayu-Undan discovery area, ten (10) per cent;


and


(b) otherwise, twenty (20) per cent;


of the petroleum produced in that year. The quantity of first tranche petroleum from crude


oil production for each calendar year shall be shared between the Designated Authority


and the contractor in accordance with the sharing percentages as provided under


subsection 3 of this Section, by apportioning it as applicable to the respective production


tranches as therein defined, using the same ratios as the production from each such


tranche over the total production of that calendar year. The quantity of first tranche


petroleum from natural gas production for each calendar year, including propane and


butane fractions extracted from natural gas but not spiked in crude oil, shall be shared


between foe Designated Authority and foe contractor in accordance with the sharing


percentages as provided under subsection 5 of this Section. The initial five (5) calendar





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years of production is to commence on the day when the first commercial production of


petroleum is produced and shall end at midnight (2400 hours) local time, being 1600


hours Greenwich Mean Time on the day preceding the fifth anniversary of this first


commercial production from the contract area."


4.10 Subsection 11 of Section 7 is deleted and the following substituted:


"7.11 Notwithstanding the provisions of subsection 1 of this Section which oblige the


contractor to market all petroleum produced from the contract area, the Designated


Authority may market any or all petroleum when the Designated Authority secures a net


realized price for the petroleum, f.o.b. the contract area, which is greater than the price


which can be realized by the contractor. The Designated Authority's right to market any


or all of the petroleum shall continue for such period as it can secure a net realized price,


f.o.b. the contract area, greater than that which can be realized by the contractor. The


contract operator shall coordinate the efficient lifting of the petroleum production,


including tanker nomination and scheduling. This subsection 11 shall not apply to natural


gas from the Bayu-Undan discovery area contracted to be sold by the contractor under


approved contracts as defined in AppendixX*


4.11 Subsection 1 of Section 8 is deleted and the following substituted:


"8.1 Petroleum production, other than natural gas the valuation of which is governed


by Section 3 of Appendix X sold to third parties shall be valued as follows:


(a) all petroleum production to which the contractor is entitled under this contract


and which is sold to third parties, shall be valued at the net realized price, f.o.b.


the contract area;


(b) all petroleum production to which the Designated Authority is entitled under this


contract which is sold to third parties shall be valued at the net realized price,


f.o.b. the contract area; and


(c) where a contract of sale involves other than a net realized price fo.b., the


Designated Authority shall determine a fair and reasonable net f.o.b. price for the


purposes of that sale."


4.12 Subsection 2 of Section 8 is deleted and the following substituted:


"8.2 Petroleum production, other than natural gas the valuation of which is governed


by Section 3 of Appendix X, sold to other than third parties shall be valued by the


Designated Authority as follows:


(a) by using the weighted average per unit price, adjusted as necessary tor quality,


quantity, grade and specify gravity of the petroleum production, received by toe


contractor and toe Designated Authority from sales to third parties during the


three (3) months preceding such sale, excluding commissions and brokerages


incurred in relation to such third party sales; and


(b) if there are no third party sales as defined in paragraph (a), at prevailing market


prices, adjusted to take account of quality, quantity, grade and specific gravity of








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the petroleum production and taking into consideration any special circumstances


with respect to sales of such petroleum production."


4.13 Subsection 6 of Section S is deleted and the following substituted:


"8.6 Petroleum production, other than natural gas the valuation of which is governed





by Section 3 of Appendix X, disposed of other than by sale or destruction shall be valued


using the method defined in subsection 2 of this Section."








SECTION 5


LIMITATION OF BENEFITS


5.1 The benefits conferred upon the contractor by this Appendix shall not be applicable to


any individual contractor party which does not, or whose affiliate does not, participate


proportionately with the other contractor parties, or their affiliates, in the export pipeline, LNG


plant (both as defined in subsection l of Section 3 of this Appendix) and other downstream


facilities, and, at the option of the Designated Authority and to the extent that neither the


Designated Authority nor either Contracting State will suffer financially thereby:


(a) the share of natural gas (for export by the said export pipeline) from the Bayu-


Undan discovery area attributable to such party under this contract pursuant to its


undivided participating interest shall be deemed to have been left in the ground


and not produced, and all such natural gas produced from the Bayu-Undan


discovery area pursuant to the development plan shall be deemed to accrue only


to the contractor parties which do so participate; and


(b) the contractor parties who do so participate shall enjoy the benefits denied by this


subsection 1 to such party.


The foregoing provisions of this Section shall only apply to an individual contractor party which


does not, or whose affiliate does not, initially so participate, and shall not apply to an individual


contractor party which subsequently, or whose affiliate subsequently, transfers its interest in the


export pipeline, LNG plant or other downstream facilities.


For the purposes of this Section:


(c) 'affiliate' shall additionally include a corporation or other entity which is under


common control with a Party to this contract and in the case of Phillips


Petroleum Timor Sea Pty Ltd or its affiliates, also includes Tokyo Gas Co., Ltd.


and its affiliates; and


(d) 'undivided participating interest* means the interest of a contractor party


identified in die Register of contractors maintained under Article 38 of the


Petroleum Mining Code.

















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