MEMORANDUM OF UNDERSTANDING
RE: SUPPLY AGREEMENTS AND PACKAGE VI SALES
This Memorandum of Understanding is dated and effective as of the
27th day of October, 1995, by and among PERUSAHAAN PERTAMBANGAN
MINYAK DAN GAS BUMI NEGARA ("PERTAMINA"); TOTAL Indonesie and
Indonesia Petroleum, Ltd., (collectively referred to as the "TOTAL
Group"); Virginia Indonesia Company, LASMO Sanga Sanga Limited,
OPICOIL Houston, Inc., Union Texas East Kalimantan Limited,
Universe Gas & Oil Company, Inc., and Virginia International
Company (collectively referred to as the "VICO Group"); Indonesia
Petroleum, Ltd., in respect of its interest in a certain portion of
the Attaka Unit (referred to as "INPEX Attaka"); and Unocal
Indonesia Company (referred to as "UNOCAL") (the TOTAL Group, the
VICO Group, INPEX Attaka, and UNOCAL each referred to as an "East
Kalimantan Contractor Group" and collectively called the "East
Kalimantan Contractors").
WITNESSETH
WHEREAS, the parties desire to confirm their mutual intention under
supply agreements entered into heretofore and hereafter ("Supply
Agreements"), to assist the East Kalimantan Gas Reserves Management
Committee ("EKGRMC") in its task of coordinating the exploitation
of East Kalimantan gas reserves so as to achieve optimum production
rates and ultimate recovery of such gas reserves and to assist each
party in planning investment in and development of the various
fields so as to assure the most favorable economic results;
WHEREAS, PERTAMINA and the East Kalimantan Contractors desire to
agree that certain sales of natural gas are to be grouped together
for the purposes of Package VI;
WHEREAS, each East Kalimantan Contractor Group is entering into
and/or will enter into supply agreements for the supply and
delivery of natural gas from such group's respective contract area
in support of the performance by PERTAMINA of its obligations under
each Package VI sales contract (hereinafter collectively called
"Package VI Supply Agreements") which provide or will provide for
the allocation as between East Kalimantan Contractor Groups of
their rights and obligations thereunder in "Producers'
Percentages";
WHEREAS, the parties have agreed to Provisional Producers'
Percentages (as hereinafter defined) provisionally applicable under
the Package VI Supply Agreements in respect of natural gas supplied
thereunder prior to determination of the Producers' Percentages
hereunder;
WHEREAS, in determining the Producers' Percentages for the Package
VI Supply Agreements, the parties are complying with PERTAMINA'S
Gas Utilization Policy; and
WHEREAS, without prejudice to PERTAMINA's future decisions with
respect to the prioritization of associated gas in the calculation
of producers' percentages for packages subsequent to Package VI,
the parties have agreed that the Producers' Percentages shall
reflect the proportions between uncommitted net gas reserves in the
East Kalimantan Contractors' respective contract areas determined
(i) based on a new estimate by the independent petroleum consultant
firm of DeGolyer and MacNaughton (hereinafter called "D&M") of the
proved recoverable reserves of natural gas in each participating
field in each such contract area as certified by D&M (hereinafter
called the "1995 D&M Certificate"), such estimate to be based on
data available on or before April 30, 1995 (hereinafter called the
"Data Cut-Off Date"), (ii) after adjustment to take into account
updated data in respect of the various supply sources in regard to
field and Lex shrinkages, fuel and flare, CO2 and inerts, Bontang
C5+, and such other items as set forth in PART TWO Section 2(b)
below, (iii) after adjustment to take into account the fuel
reallocation as set forth in PART TWO Section 2(c) below, and (iv)
after deduction of prior commitments of natural gas.
NOW, IT IS HEREBY AGREED AS FOLLOWS:
PART ONE
1. The provisions of PART ONE shall apply to all Supply
Agreements under which natural gas from fields in East
Kalimantan are committed by an East Kalimantan Contractor
Group in support of PERTAMINA's obligations under natural gas
sales contracts. So that in the implementation of this PART
ONE all of the rights and abilities conveyed to one field and
one PSC area shall also be conveyed to all fields and to all
PSC areas on the same or otherwise compatible basis, the
collective terms "Attaka Contract Gas" and "Attaka Field" as
they appear in any Supply Agreement shall hereafter be
substituted by or otherwise mean, respectively, "INPEX
Contract GAS and UNOCAL Contract Gas" and "INPEX Contract Area
and UNOCAL Contract Area", individually or collectively as
such terms apply.
2. In order to optimize the economic recovery of natural gas,
each East Kalimantan Contractor Group may, subject to
PERTAMINA's approval, deliver natural gas ("Substitute Gas")
from any participating field(s) under the Supply Agreements
(the "Supplying Field") in substitution for deliveries from
another participating field(s) (the "Substituted Field");
however, if Substitute Gas can be delivered more economically
from field(s) other than the participating field(s), then
PERTAMINA will decide accordingly. The details regarding any
plans for deliverability substitution (including the period of
time, quantity of gas and fields involved) shall be reviewed
and studied by the EKGRMC in accordance with PERTAMINA's
guidelines so as to optimize, on an economic basis, the
recovery of natural gas reserves from the East Kalimantan gas
supply area ("Gas Supply Area"). Any such substitution shall
not affect the aggregate rates of production to be maintained
in respect of such PSC as provided in the annual plan
determined by the EKGRMC.
3. Deliverability substitution under this Memorandum of
Understanding shall not affect the requirement to supply the
aggregate quantities of net natural gas that a field has
contributed towards the "Contract Gas" committed under each
Supply Agreement. Substitute Gas shall for the purposes of
the Supply Agreements be treated as if it had been produced
from the Substituted Field. The Substitute Gas shall be
deemed to be stored in the Substituted Field on behalf of the
Supplying Field (hereinafter referred to as "Stored Gas").
4. In accordance with PERTAMINA's policy of production priority
for associated gas, associated gas produced and delivered from
a field may be treated as if such gas had been produced from
a field or fields within the Gas Supply Area; in such event,
the quantity of associated gas produced is deemed to be stored
in the other field(s). No substitution under this Memorandum
of Understanding shall have the effect of limiting the
production priority of associated gas as a substitute for non-
associated gas.
5. Stored Gas resulting from deliverability substitution and
associated gas deemed stored as a result of production
priority shall be available for future delivery in support of
PERTAMINA's obligations.
6. Notwithstanding the above, in order to optimize the economic
recovery of natural gas, INPEX Attaka may, subject to
PERTAMINA's approval, deliver natural gas ("INPEX Substitute
Gas") from any participating field(s) under the Supply
Agreements in the UNOCAL PSC area (the "UNOCAL Supplying
Field") in substitution for deliveries from an INPEX
participating field (the "INPEX Substituted Field"). The
details regarding any plans for deliverability substitution
with INPEX Substitute Gas shall be reviewed and studied by the
EKGRMC in accordance with PERTAMINA's guidelines so as to
optimize, on an economic basis, the recovery of natural gas
reserves from the Gas Supply Area. Any substitution with
INPEX Substitute Gas shall not affect the sum of the aggregate
rates of production to be maintained in respect of the INPEX
Attaka PSC and UNOCAL PSC, as such rates are provided in the
annual plan determined by the EKGRMC. INPEX Substitute Gas
shall for the purposes of the Supply Agreements be treated as
if it had been produced from the INPEX Substituted Field. The
INPEX Substitute Gas shall be deemed to be stored in the INPEX
Substituted Field on behalf of the UNOCAL Supplying Field
(hereinafter referred to as "INPEX Stored Gas"). INPEX Stored
Gas shall be available for future delivery in support of
PERTAMINA's obligations.
PART TWO
1. Provisional Producers' Percentages
The Provisional Producers' Percentages (and the provisional
allocation of supply commitments as between the East
Kalimantan Contractors under the Package VI Supply Agreements)
are:
- INPEX Attaka Producers' Percentage: 1.6% (one decimal six
percent)
- TOTAL Group Producers' Percentage: 72.2% (seventy-two
decimal two percent)
- UNOCAL Producers Percentage: 4.6% (four decimal six
percent)
- VICO Group Producers' Percentage: 21.6% (twenty-one
decimal six percent)
The use of the Provisional Producers Percentages is
provisional pending determination hereunder of the Producers'
Percentages, and the Producers' Percentages shall apply and be
deemed to have applied with retroactive effect from the
effective date of each Package VI Supply Agreement.
Accordingly, for the purposes of any Package VI Supply
Agreement under which natural gas has been supplied before the
determination of the Producers' Percentages, (i) the volumes
of natural gas required to have been delivered shall be
accordingly adjusted, and (ii) arrangements will be made for
the parties which have been overpaid as a result of the
interim use of the Provisional Producers Percentages to
compensate (but such compensation shall not include interest)
any parties which have been underpaid as a result thereof,
such compensation to be made by cash settlement no later than
thirty (30) calendar days after the execution of the
Supplemental Memorandum referred to in Section 6 below.
2. Determination of Producers' Percentages
The Producers' Percentages and the allocation of supply
commitments as between the East Kalimantan Contractors under
each of the Package VI Supply Agreements shall be determined
on the basis of the principles and procedures set forth in
this Section 2. Table 1 attached and hereby incorporated
herewith represents the proper method of calculation of
Initial Adjusted Net Gas Reserves of each participating field.
In the event of any conflict between any provision contained
in the text of this Memorandum of Understanding and anything
contained in Table 1, the provision contained in the text
shall prevail. References to specific sections or paragraphs
shall be interpreted as referring to specific sections or
paragraphs of this PART TWO.
(a) D&M Reserves
The estimate of each fields proved initial recoverable
wet-gas reserves expressed in billions of standard cubic
feet ("BSCF") of wet-gas, as certified in the 1995 D&M
Certificate (the "D&M Reserves"), shall serve as the
basis for determination of the Producers' Percentages.
The field's D&M Reserves, minus its total wet-gas
production (i.e. wellhead gas plus field condensate) as
of December 31, 1994 ("Past Field Production"), shall be
hereinafter referred to as its "Remaining D&M Reserves
After Production".
(b) Determination of Net Gas
The D&M Reserves for each field shall be adjusted by
deducting the following amounts (expressed in BSCF) to
determine the amount of net natural gas deemed available
to each field ("Initial Net Gas Reserves").
(1) PAST FIELD CONDENSATE SHRINKAGE shall be the
actual/measured amount of condensate shrinkage for
the field during the period up to and including
December 31, 1994, but not including any Lex
shrinkage; the amount shall also be expressed as a
percentage of Past Field Production.
(2) FUTURE FIELD CONDENSATE SHRINKAGE shall be
calculated by determining the average annual amount
of condensate shrinkage (excluding Lex shrinkage)
over the shorter of (a) the period since production
began; or (b) the last five Years, expressed as a
percentage of wet-gas production, and applying such
percentage to the field's Remaining D&M Reserves
After Production; provided, however, that if data
for at least one Year is unavailable due to
insufficient production history of the field, or if
based on a production plan of the remaining D&M
Reserves the quantities of field condensate
shrinkage would be modified, then evidence shall be
produced to substantiate the expected condensate
shrinkage, and calculated values, after
substantiation, shall be deemed representative of
the Future Field Condensate Shrinkage. In
particular, for the fields named in the LEMIGAS
letter dated April 27, 1995, the calculation
methodology described in such letter shall be
followed.
(3) PAST FIELD FLARE shall be the actual/measured
amount (or if the actual/measured amount is
unavailable, the calculated amount) of gas flared
by the field during the period up to and including
December 31, 1994, but not including any Lex flare;
the amount shall also be expressed as a percentage
of Past Field Production.
(4) FUTURE FIELD FLARE shall be calculated by
determining the lowest amount of gas flared
(excluding Lex flare) in any one Year of the last
five years, expressed as a percentage of wet-gas
production, and applying that percentage to the
field's Remaining D&M Reserves After Production;
provided, however, that if data for at least five
Years is unavailable due to insufficient production
history of the field or if a Development Project is
anticipated which would modify the quantities of
gas flared, then evidence shall be produced to
substantiate the expected field flare, and
calculated values, after substantiation, shall be
deemed representative of the Future Field Flare.
(5) PAST FIELD FUEL shall be the actual/measured amount
of fuel consumed by the field during th period up
to and including December 31, 1994, but not
including any Lex fuel; the amount shall also be
expressed as a percentage of Past Field Production.
(6) FUTURE FIELD FUEL shall be calculated by
determining the total amount of fuel gas (excluding
Lex fuel) required to produce the field's Remaining
D&M Reserves After Production. Such calculation
shall take account of the anticipated annual fuel
requirements based on the field facilities required
to produce the field's Remaining D&M Reserves After
Production and shall be consistent with the field
abandonment pressure utilized by D&M in the 1995
D&M Certificate. Unless otherwise justified by
standard petroleum engineering practices or by the
limited amount of remaining D&M Reserves in a given
participating field, as approved by PERTAMINA after
consultation at the EKGRMC or its reserves sub-
committee, such field's future fuel gas
requirements shall be calculated on the assumption
that such field will be maintained in production
until the end of the Production Sharing Contract
covering the field. The amount shall also be
expressed as a percentage of Remaining D&M Reserves
After Production. The calculated values after
substantiation shall be deemed representative of
Future Field Fuel.
Wet-gas field shrinkage, flare and fuel is referred to as
"Gas to Lex". The numbers resulting after subtraction
respectively of (1), (3) and (5) above from the field's
Past Field Production, and of (2), (4) and (6) above from
the field's Remaining D&M Reserves After Production,
shall hereinafter be referred to respectively as the
field's "Past Gas to Lex" and the field's "Future Gas to
Lex".
(7) PAST LEX SHRINKAGE shall be the actual/measured
amount (or if the actual/measured amount is
unavailable, the calculated amount) of shrinkage at
the Lex plant during the period up to and including
December 31, 1994; the amount shall also be
expressed as a percentage of Past Gas to Lex.
(8) FUTURE LEX SHRINKAGE shall be calculated by
determining the average annual amount of Lex
shrinkage over the shorter of (a) the period since
production began; or (b) the last five Years,
expressed as a percentage of Gas to Lex, and
applying such percentage to the field's Future Gas
to Lex; provided, however, that if a Development
Project is anticipated which would modify the
quantities of Lex shrinkage, then evidence shall be
produced to substantiate the expected Lex
shrinkage, and calculated values, after
substantiation, shall be deemed representative of
the Future Lex Shrinkage.
(9) PAST LEX FUEL shall be the actual/measured amount
of Lex fuel gas during the period up to and
including December 31, 1994; the amount shall also
be expressed as a percentage of Past Gas to Lex.
(10) FUTURE LEX FUEL shall be calculated by determining
the average annual amount of Lex fuel gas over the
shorter of (a) the period since production began;
or (b) the last five Years, expressed as a
percentage of Gas to Lex, and applying that
percentage to the field's Future Gas to Lex;
provided, however, that if a Development Project is
anticipated which would modify the quantities of
Lex fuel gas, then evidence shall be produced to
substantiate the expected Lex fuel gas, and
calculated values, after substantiation, shall be
deemed representative of the Future Lex Fuel.
(11) PAST LEX FLARE shall be the actual/measured amount
(or if the actual/measured amount is unavailable,
the calculated amount) of Lex flared gas during the
period up to and including December 31, 1994; the
amount shall also be expressed as a percentage of
Past Gas to Lex.
(12) FUTURE LEX FLARE shall be calculated by determining
the lowest amount of Lex flared gas in any one Year
of the last five Years, expressed as a percentage
of Gas to Lex, and applying that percentage to the
field's Future Gas to Lex; provided, however, that
if a Development Project is anticipated which would
modify the quantities of Lex flared gas, then
evidence shall be produced to substantiate the
expected Lex flared gas, and calculated values,
after substantiation, shall be deemed
representative of the Future Lex Flare.
Gas to Lex less Lex shrinkage, fuel and flare is referred
to as "Inlet Gas". The numbers resulting after
subtraction respectively of (7), (9) and (11) above from
the field's Past Gas to Lex, and of (8), (10) and (12)
above from the field's Future Gas to Lex, shall
hereinafter be referred to respectively as the field's
"Past Inlet Gas" and the field's "Future Inlet Gas".
(13) PAST CO2 AND INERTS shall be the actual/measured
amount of CO2 and inerts contained in the Inlet Gas
(determined by Inlet Gas analysis) during the
period up to and including December 31, 1994; the
amount shall also be expressed as a percentage of
Past Inlet Gas.
(14) FUTURE CO2 AND INERTS shall be calculated by
determining the average annual amount of CO2 and
inerts over the shorter of (a) the period since
production began; or (b) the last five Years,
expressed as a percentage of Inlet Gas, and
applying such percentage to the field's Future
Inlet Gas; provided, however, that if data for at
least one Year is unavailable due to insufficient
production history of the field or if based on a
production plan of the remaining D&M Reserves the
quantities of CO2 and inerts would be modified
considering the initial CO2 and inerts estimated to
be contained in such field, then evidence shall be
produced to substantiate the expected CO2 and
inerts, and calculated values, after
substantiation, shall be deemed representative of
the Future CO2 and Inerts.
(15) PAST BONTANG C5+ shall be the actual/measured
amount of Bontang C5+ contained in the Inlet Gas
(determined by Inlet Gas analysis) during the
period up to and including December 31, 1994; the
amount shall also be expressed as a percentage of
Past Inlet Gas.
(16) FUTURE BONTANG C5+ shall be calculated by
determining the average annual amount of Bontang
C5+ contained in the Inlet Gas (determined by Inlet
Gas analysis) over the shorter of (a) the period
since production began; or (b) the last five Years,
expressed as a percentage of Inlet Gas, and
applying such percentage to the field's Future
Inlet Gas; provided, however, that if data for at
least one Year is unavailable due to insufficient
production history of the field or if a Development
Project is anticipated which would modify the
quantities of C5+, then evidence shall be produced
to substantiate the expected C5+, and calculated
values, after substantiation, shall be deemed
representative of the Future Bontang C5+.
For the purposes of (1) to (16) above:
(i) A "Year" is a calendar year during all or
substantially all of which the field was in
production; references to the last five Years are
to the five Years ending December 31, 1994.
(ii) A "Development Project" shall be based on the 1995
D&M Certificate and shall include the following
projects:
(1) Tambora/Tunu Fields Development Project;
(2) Peciko Field Development Project;
(3) Sisi Field Development Project;
(4) Pamaguan Field Development Project;
(5) Mutiara Field Additional Compression Project;
(6) Santan Field Development Project;
(7) Melahin/Kerindingan Fields Development
Projects;
(8) Serang Field Development Project;
(9) Nubi Field Development Project;
(10) Lampake Field Development Project; and
(11) Any other project for which a project proposal
has been approved by PERTAMINA no later than
October 31, 1995.
(iii) For any particular field, where future
deductions are to be based on a period of time
shorter than five Years or are to be based in
substantiated expected values, such deductions
shall be made on a consistent basis using,
where appropriate, comparable periods of time,
and shall exclude any unreliable data (i.e.
data which is outside the range of normal
technical practice or which cannot be
demonstrated to be reproduced regularly in the
future). In particular, Future Field Flare
and Future Lex Flare will be calculated on the
basis of the same Year.
(iv) In the calculation of Future Lex Shrinkage, Fuel
and Flare, PERTAMINA's decision (ref:
4081/LOD30/93-S1) dated September 9, 1993 set out
in Section A shall apply with the exception of the
last sentence referring to "actual data" and in
lieu thereof, the most up-to-date relevant data
shall be utilized. The calculation shall recognize
that Lex comprises: the Santan Terminal Lex Plant
("STLP"), the Santan Compressor Station ("SCS") and
the Santan Terminal Oil Processing Facilities
("STOPF"). Further, gas may only bypass the STLP
if the maximum processing capacity of the STLP is
utilized ("Bypass Gas"); STLP shrinkage shall only
apply to gas that is processed in the STLP;
shrinkage in respect of Bypass Gas shall be
accounted for in the SCS and the STOPF (if
applicable) only; and all future fuel and flare
amounts (excluding future field fuel and flare
already accounted for) which are expected to be
utilized to produce the Future Gas to Lex,
including the gas to be processed through the Lex
and Bypass Gas, are to be accounted for in the
Future Lex Fuel and the Future Lex Flare.
Wet-gas less (when applicable): field shrinkage, flare
and fuel; Lex shrinkage, flare and fuel; CO2 and inerts;
and Bontang C5+ is referred to as "Net Gas". The number
resulting after subtraction of (1) to (16) from the
field's D&M Reserves shall be the field's Initial Net
Gas Reserves".
(c) Santan/Bontang Fuel
(1) The field's Initial Net Gas Reserves shall be
adjusted for past and future Santan fuel gas. Past
and future Santan fuel gas attributable to the
operations in respect of the hydrocarbons received
from Badak Central and handled at the Santan
Terminal shall be allocated to the VICO Group
fields and Total Group fields in the same amounts
as determined in Package IV for Santan fuel gas
reallocation.
(2) In recognition that the EKGRMC has determined that
it is not appropriate from a technical standpoint
to adjust the field's reserves for past and future
gas consumed at the Bontang Plant, for the removal
of the CO2 component and for the removal, handling
and transportation to Badak Central of the C5+
components, no such adjustment shall be made to the
field's Initial Net Gas Reserves in determining the
Producers' Percentages hereunder.
For each field, the number resulting after adjustment for
Santan fuel gas reallocation under Section 2(c)(1) shall
be the field's "Initial Adjusted Net Gas Reserves".
(d) Determination of Net Gas Requirement for Prior Sales
Commitments
The Net Gas requirement (expressed in BSCF) for the sales
commitment of each "Package" (groupings of gas sales
supply commitments, i.e., Packages I, II, III, KCO, IV
and V) shall be comprised of the following:
(1) the LNG and LPG component;
(2) the KFP component; and
(3) the KMI component.
The amount of the LNG and LPG component for each Package
shall be determined on the basis of the calculated Net
Gas Bontang Plant efficiency (for LNG and LPG sales),
considering the average hydrocarbon heating value ("HHV")
of the Net Gas at the Bontang Plant. The commitments for
each Package will be further adjusted based on an
estimated HHV of the corresponding Net Gas of each
Package. The applicable Bontang Plant efficiency shall
be (i) for each year up to and including December 31,
1994, the actual observed efficiency based on gas
delivered from the fields and BTU's of LNG and LPG
produced by the Bontang Plant for that year, and (ii)
from January 1, 1995 onwards, the average of the Bontang
Plant efficiencies for the five years to December 31,
1994 as determined under (i).
The amount of the KFP component shall be determined by
adding (i) the gas received and paid for at KFP adjusted
for past fuel and flare at the SKG Compressor Station up
to December 31, 1994, and (ii) the remaining contractual
amounts from January 1, 1995 to the end of each contract
adjusted for future fuel and flare at the SKG Compressor
Station. The future fuel and flare at the SKG Compressor
Station will be determined using the average of the last
five years of the past fuel and flare.
The amount of the KMI component shall be determined on
the basis of the contractual amounts of gas to be
supplied to KMI.
(e) Deduction of Prior Commitments
Each field's Initial Adjusted Net Gas Reserves shall
serve as the basis for determining the amount of natural
gas remaining unallocated and thus available to be
allocated to meet the supply commitments of the east
Kalimantan Contractors under the Package VI Supply
Agreements.
The following supply contributions shall be calculated
for each field:
(1) NET GAS ALLOCABLE TO PACKAGE I
(2) NET GAS ALLOCABLE TO PACKAGE II
(3) NET GAS ALLOCABLE TO PACKAGE III
(4) NET GAS ALLOCABLE TO KCO
(5) NET GAS ALLOCABLE TO PACKAGE IV
(6) NET GAS ALLOCABLE TO PACKAGE V
using the percentages as set forth in Table 2 attached
and hereby incorporated herewith. Such contributions
shall be hereinafter referred to as the "Prior Net Gas
Commitment" for each East Kalimantan Contractor Group's
fields.
For each East Kalimantan Contractor Group's fields, the
figures resulting after deducting its Prior Net Gas
Commitment from its Initial Adjusted Net Gas Reserves
shall be deemed its "Uncommitted Net Gas Reserves".
(f) Package VI Sales
It is agreed that the following are to be grouped
together (hereinafter called "Package VI Sales"):
1. All quantities of LNG sold pursuant to the
Memorandum of Agreement dated October 6, 1994 Re:
1981 LNG Sales Contract Extension in respect of the
period April 1, 2003 to March 31, 2008;
2. All quantities of LNG sold pursuant to the
Memorandum of Mutual Intent with Korea Gas
Corporation dated July 22, 1994 for Purchase and
Sale of LNG, in respect of the period 2000 to 2017;
3. All quantities of LNG sold pursuant to the
Memorandum of Understanding with CPC dated December
6, 1994 for Purchase and Sale of LNG, in respect of
the period 2000 to 2017;
4. Any natural gas quantities sold under new domestic
sales contracts entered into before January 1,
2000, provided that the first delivery of Natural
Gas pursuant to such contract is scheduled to
commence, at the time such contract is entered
into, before January 1, 2000 (but not including:
a. any Bontang LPG sales; and
b. any quantities sold under sales contracts not
supported by the reserves from each PSC area
as certified by the 1995 D&M Certificate).
Notwithstanding the above, in no event shall Package VI
Sales include any quantities allocated to prior gas
commitments (i.e. Packages I, II, III, KCO, IV and V).
For the avoidance of doubt: Package IV prior gas supply
commitments shall be those quantities defined as Package
IV Sales under section 2(f) of the Memorandum of
Understanding Re: Supply Agreements and Package IV Sales
dated August 12, 1991 ("Package IV MOU"); and Package V
prior gas supply commitments shall be those quantities
defined as Package V Sales under section 2(f) of the
Memorandum of Understanding Re: Supply Agreements and
Package V Sales dated October 5, 1994 ("Package V MOU")
which quantities shall represent the best estimate, as of
October 31, 1995, of Package IV Sales and Package V
Sales.
It is agreed that the Producers' Percentages as
determined herein shall apply to Package VI Sales.
(g) Determination of Producers' Percentages
Each East Kalimantan Contractor Group s Producers
Percentage shall be equal to the ratio that the volume of
the Uncommitted Net Gas Reserves of such group's fields
bears to the aggregate volume of the Uncommitted Net Gas
Reserves from all fields. The aggregate Net Gas
requirement for Package VI Sales shall be supplied by
each East Kalimantan Contractor Group in proportion to
such group's Producers' Percentage.
3. Participating Fields
For the purposes of PART TWO of this Memorandum of
Understanding, a participating field shall mean a field within
the Gas Supply Area which is included in the 1995 D&M
Certificate and either:
(a) is a participating field pursuant to the Package V MOU as
supplemented on May 31, 1995; or
(b) has received an approval in principle from PERTAMINA for
a Plan Of Development no later than October 31, 1995.
4. Lemigas Mass Balance Study
Unless otherwise agreed between the East Kalimantan
Contractors, the data to be utilized for the purposes of
Section 2 above shall be based on the data included in a new
Lemigas study of Mass Balance for East Kalimantan
participating fields (hereinafter called the "Lemigas Mass
Balance Study Package VI"). Therefore, each of TOTAL
Indonesie, Virginia Indonesia Company, and UNOCAL (in its
capacity as operator of its respective group) shall use its
best efforts to assist Lemigas to prepare the Lemigas Mass
Balance Study Package VI based on accurate production data up
to December 31, 1994. In this regard, TOTAL Indonesie,
Virginia Indonesia Company, and UNOCAL shall promptly furnish
Lemigas with all information needed by Lemigas to prepare the
Lemigas Mass Balance Study Package VI. Each operator shall
use its best efforts to ensure that the lemigas Mass Balance
Study Package VI includes accurate data up to December 31,
1994 on its production sharing contract area and to ensure
that the Lemigas Mass Balance Study Package VI is available
for use by the parties as soon as possible.
5. EKGRMC
To ensure a timely and accurate determination of Producers'
Percentages, the parties hereto instruct the EKGRMC to monitor
and, when considered prudent, to verify the accuracy of any
and all data supporting the calculation of Producers
Percentages.
6. Supplemental Memorandum
The determination of Producers' Percentages shall be completed
as soon as practicable and the parties hereto shall thereupon
execute a memorandum supplemental ("Supplemental Memorandum")
to this Memorandum of Understanding confirming the
participating fields and the Producers' Percentages. Such
Supplemental Memorandum shall be executed no later that twelve
(12) months after the Data Cut-Off Date.
IN WITNESS WHEREOF, the parties have caused this Memorandum of
Understanding to be executed by their duly authorized
representatives as of the date first above written.
PERUSAHAAN PERTAMBANGAN MINYAK
DAN GAS BUMI NEGARA
(PERTAMINA)
By /S/
VIRGINIA INDONESIA COMPANY
By /S/
TOTAL INDONESIE
By /S/
UNOCAL INDONESIA COMPANY
By /S/
OPICOIL HOUSTON INC.
By /S/
INDONESIA PETROLEUM, LTD.
By /S/
VIRGINIA INTERNATIONAL COMPANY
By /S/
LASMO SANGA SANGA LIMITED
By /S/
UNION TEXAS EAST KALIMANTAN
LIMITED
By /S/
UNIVERSE GAS & OIL COMPANY,
INC.
By /S/
TABLE 1
UNCOMMITTED NET GAS RESERV ES
_______________ FIELD (BSC F)
Status as at 31/12/94 Future
Percent Amount Percent Amount
(%) BSCF (%) BSCF
1. D&M Initial Reserves* (BSCF)
2. Past Field Production (BSCF)
3. Remaining Reserves (BSCF)
4. Field Shrinkage (% of 2 or 3, BSCF)
5. Field Flare (% of 2 or 3, BSCF)
6. Field Fuel (% of 2 or 3, BSCF)
7. Gas to LEX (BSCF)
8. LEX Shrinkage (% of 7, BSCF)
9. LEX Fuel (% of 7, BSCF)
10. LEX to Flare (% of 7, BSCF)
11. Inlet Gas Available (BSCF)
11.a CO2 + Inerts (% of 11, BSCF)
11.b Bontang Condensate C5+ (% of 11, BSCF)
12. Net Gas Produced (BSCF)
13. Net Gas Remaining (BSCF)
14. Initial Net Gas Reserves (BSCF) ______
15. Santan Fuel Gas Reallocation (BSCF) ______ _____
16. Initial Adjusted Net Gas Reserves (BSCF) ______
17. Prior Net Gas Commitments (BSCF) ______
18. Uncommitted Net Gas Reserves (BSCF) ______
* Reserves from 1995 D&M Certificate.
/TABLE
TABLE 2
FIELD'S CONTRIBUTION PERCENTAGES
FIELD PACKAGE I PACKAGE II PACKAGE III KCO PACKAGE IV PACKAGE V
Badak 100.0000% 30.2840% 2.3594% 3.0500% 6.7978% 7.2911%
Nilam - 45.1713% 20.1902% 29.9933% 13.2347% 9.2893%
Mutiara - - 5.6098% 12.0394% 3.8824% 2.8781%
Semberah - - 5.2399% 10.5511% 5.6929% 3.3058%
Pamaguan - - - - 0.1990% 0.0990%
Lampake - - - - - 0.6105%
HDL/BKP - 20.1619% 22.9595% 13.5315% 0.4194% 0.9260%
Tambora - - 9.9829% 8.2966% 8.9426% 4.1118%
Tunu - - 8.8424% 7.5381% 27.7561% 34.8886%
Sisi - - - - 6.7013% 2.9807%
Nubi - - - - - 2.4223%
Peciko - - - - 14.2948% 25.0499%
Attaka - 4.3828% 24.8159% 15.0000% 9.0326% 3.1320%
Melahin - - - - 0.4455% 0.0426%
Kerindingan - - - - 0.2033% 0.1004%
Serang - - - - 1.4621% 2.3612%
Santan - - - - 0.9355% 0.5107%
SUM 100.0000% 100.0000% 100.0000% 100.0000% 100.0000% 100.0000%
PSC GROUP PACKAGE I PACKAGE II PACKAGE III KCO PACKAGE IV PACKAGE V
VICO 97.9000% 66.4310% 29.6004% 50.0000% 27.2064% 21.5956%
TOTAL 2.1000% 29.1862% 45.5837% 35.0000% 60.7146% 72.2575%
UNOCAL 0.0000% 2.1914% 12.4048% 7.5000% 7.5627% 4.5809%
INPEX ATTAKA 0.0000% 2.1914% 12.4080% 7.5000% 4.5163% 1.5660%
SUM 100.0000% 100.0000% 100.0000% 100.0000% 100.0000% 100.0000%