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AMENDMENT TO PRODUCTION SHARING CONTRACT
JPDA 03-13
This amendment to production sharing contract 03-13 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 JPDA Pty Ltd ABN 17 054 424 109,
a corporation organised and existing under die laws of Australia, ConocoPhillips (91-13) Pty Ltd
ABN 77 099 996 782, a corporation organised and existing under the laws of Australia, Phillips
Petroleum Timor Sea Pty Ltd ABN 39 000 751 593, a corporation organised and existing under
the laws of Australia and Eni JPDA 03-13 Limited ARBN 054 729 930 a corporation existing and
organised under the laws of England 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 03-13 is hereby
attached to and made a part of the 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 five original copies
and in the English language, on this 16 day of May, 2003.
THE DESIGNATED AUTHORITY
BY Q,
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CONOCOPHILLIPS JPDA PTY LTD ABN 17 054 424 109
CONOCOPH1LLIPS (91-13) PTY LTD ABN 77 099 996 782
PHILLIPS PETROLEUM TIMOR SEA PTY LTD ABN 39 000 751 593
ENI JPDA 03-13 LIMITED ARBN 054 729 930
BY u
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3:45 PM
APPROVED BY THE JOINT COMMISSION on this 16 day of May 2003
BY _LOji-
prts-? erftfOfr'rc
JOINT COMMISSIONER JOINT COMMISSIONER
FOR TIMOR-LESTE FOR AUSTRALIA
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APPENDIX X
TO PRODUCTION SHARING CONTRACT JPDA 03-13
In this Appendix,
’Approved contract1 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 point’ 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 die 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 die 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 hinds 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 the 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) fails 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
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(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
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
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Section from time to time. The decommissioning costs reserve for a year shall be determined by
the formula:
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 the 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 the 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 (including 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 die Designated Authority. The contractor
shall promptly advise the Designated Authority if a party to the unit operating agreement fails 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 (16*) 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 the 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
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force of the Treaty, and further assuming that the owners are
special purpose vehicles having no other business, and
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
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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
to the extent such are incurred on and from die date of commencement of regular
downstream deliveries in respect of die 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 die 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 die 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.
'LNG plant* means the liquefied natural gas plant as identified in the development plan.
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'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
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 the approved contract.
3.4 In any month, die 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.
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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
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 the downstream
facilities shall be reserved by the contractor and, to the extent that that capacity is used for natural
gas from other than the 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, the 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 die 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 foe Bayu-Undan discovery area, only that proportion of
the cost which relates to that natural gas shall be allowed.
3.13 If foe buyer under any approved contract for the 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 foe 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 foe field export point; and
(b) downstream operating costs, if such costs are incurred beyond the field export
point;
only when such costs are incurred.
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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
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:
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"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:
(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;
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(h) any amounts received as charges for the use of employee amenities, die cost of
which is an operating cost; and
(i) any amounts received in respect of expenditures which are operating costs, by
way of indemnity or compensation for the 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;
(j) costs incurred as a result of non-compliance by the contract operator with die
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 ofSection 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 ofAppendix X; and
(m) the export cost charge as defined in subsection 1 of Section 3 of Appendix X.n
4.6 Subsection 5 of Section 7 is deleted and the following substituted:
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"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
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, hi 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
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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 the Designated Authority and the contractor in accordance with the sharing
percentages as provided under subsection 5 of this Section. The initial five (5) calendar
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 {nice,
f.o.b. the contract area; and
(c) where a contract of sale involves other than a net realized price f.o.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 die weighted average per unit price, adjusted as necessary for quality,
quantity, grade and specify gravity of the petroleum production, received by the
contractor and the 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
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(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
the petroleum production and taking into consideration any special circumstances
with respect to sales of such petroleum production."
4.13 Subsection 6 of Section 8 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 1 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 the Register of contractors maintained under Article 38 of the
Petroleum Mining Code.
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