<PAGE> 1
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FORM 10-K
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1995
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
COMMISSION FILE NUMBER 1-9019
UNION TEXAS PETROLEUM HOLDINGS, INC.
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
DELAWARE
(STATE OR OTHER JURISDICTION OF INCORPORATION OR ORGANIZATION)
76-0040040
(I.R.S. EMPLOYER IDENTIFICATION NO.)
1330 POST OAK BOULEVARD, HOUSTON, TEXAS
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES)
77056
(ZIP CODE)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: (713) 623-6544
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
<TABLE>
<CAPTION>
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
---------------------------------- ----------------------------------
<S> <C>
Common Stock, $.05 par value New York Stock Exchange
Pacific Stock Exchange
8.25% Senior Notes due 1999 New York Stock Exchange
</TABLE>
SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT: NONE
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No
--- ---
Indicate by check mark if disclosure of delinquent filings pursuant to Item
405 of Regulation S-K (sec. 229.405 under the Securities Exchange Act of 1934)
is not contained herein, and will not be contained, to the best of registrant's
knowledge, in definitive proxy or information statements incorporated by
reference in Part III of this Form 10-K or any amendment to this Form 10-K. /X/
As of February 29, 1996, there were 87,597,350 shares of Union Texas
Petroleum Holdings, Inc. $.05 par value Common Stock issued and outstanding,
65,590,855 of which, having an aggregate market value of $1,295,419,386, were
held by non-affiliates of the registrant. For purposes of the above statement
only, all directors and executive officers of the registrant are assumed to be
affiliates.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Proxy Statement related to the registrant's 1996 Annual
Stockholders Meeting are incorporated by reference into Part III of this report.
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<PAGE> 2
TABLE OF CONTENTS
<TABLE>
<CAPTION>
PAGE
----
<C> <S> <C>
PART I
Item 1. Business..................................................................... 1
Overview................................................................... 1
Segment Data............................................................... 3
Reserves................................................................... 4
Production................................................................. 6
Oil and Gas Prices and Production Costs.................................... 6
Current Markets for Oil and Gas............................................ 7
Acreage.................................................................... 7
Drilling Activities........................................................ 7
International Exploration and Production................................... 8
Indonesia............................................................... 8
U.K. North Sea.......................................................... 14
Pakistan................................................................ 17
Other International..................................................... 18
Alaska..................................................................... 20
Petrochemicals............................................................. 20
Plant Operations........................................................ 20
Storage and Transportation.............................................. 21
Other Matters.............................................................. 21
Environmental........................................................... 21
Insurance............................................................... 22
Competition............................................................. 22
Regulation of Oil and Gas Production and Marketing...................... 22
Employees............................................................... 22
General................................................................. 22
Item 2. Properties................................................................... 23
Item 3. Legal Proceedings............................................................ 23
Item 4. Submission of Matters to a Vote of Security Holders.......................... 23
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters........ 24
Item 6. Selected Financial Data...................................................... 25
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations...................................................... 26
Item 8. Financial Statements and Supplementary Data.................................. 32
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure....................................................... 58
PART III
Item 10. Directors and Executive Officers of Registrant............................... 59
Item 11. Executive Compensation....................................................... 59
Item 12. Security Ownership of Certain Beneficial Owners and Management............... 59
Item 13. Certain Relationships and Related Transactions............................... 59
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K.............. 59
</TABLE>
<PAGE> 3
PART I
ITEM 1. BUSINESS.
OVERVIEW
The Company, the successor to a corporation founded in 1896, is a
U.S.-based independent (non-integrated) oil and gas company with worldwide
operations. At December 31, 1995, the Company had proved oil and gas reserves of
435 million barrels of oil equivalent. All of the Company's oil and gas
producing activities are currently conducted outside of the United States,
primarily in Indonesia, the United Kingdom (the "U.K.") sector of the North Sea
and Pakistan. The Company also owns an interest in a U.S.-based petrochemical
business.
Unless the context otherwise requires, all references herein to the Company
are not intended to imply exact corporate relationships and include Union Texas
Petroleum Holdings, Inc., its predecessors and its subsidiaries, including their
interests in certain partnerships. Union Texas Petroleum Holdings, Inc. was
organized under the laws of the State of Delaware in 1982. The address and
telephone number of the Company's principal executive offices are 1330 Post Oak
Blvd., Houston, Texas 77056, (713) 623-6544. As of February 29, 1996, the
Company had approximately 1,100 full-time employees worldwide.
The Company's principal current international activities began in the late
1960s with its participation in a joint venture in Indonesia and in two
consortia in the U.K. North Sea. In addition, the Company is currently engaged
in exploration and production activities in several other countries.
International oil and gas properties accounted for 100% of the Company's total
proved reserves as of December 31, 1995. A significant portion of the Company's
net income attributable to its oil and gas operations in recent periods
(excluding the gain on the sales of the Company's U.S. businesses made in 1991)
has been generated by its international operations.
The Company's Indonesian activities consist primarily of its 37.81% working
interest in a joint venture that produces natural gas and, to a lesser extent,
oil and condensate from several fields in East Kalimantan, Indonesia. The
Company holds its interests in this joint venture directly through a wholly
owned subsidiary and also indirectly through its 50% interest in Unimar Company
("Unimar"), which is a partnership with a subsidiary of LASMO plc, a U.K.
company. Unimar owns ENSTAR Corporation and its subsidiaries, including Virginia
Indonesia Company, the operator of the joint venture. The Company's interests in
Unimar are reported on its Consolidated Financial Statements as an equity
investment (the "Equity Partnership"). See Notes 5 and 17 of Notes to
Consolidated Financial Statements for additional information regarding the
Equity Partnership.
Natural gas produced by the East Kalimantan joint venture is converted into
liquefied natural gas ("LNG") at facilities owned by Pertamina, the Indonesian
national oil company. Currently, LNG is principally sold to two groups of
Japanese industrial and utility customers, the national oil company of the
Republic of China, a consortium of buyers organized by Osaka Gas, and Korea Gas
Corporation, under long-term contracts originally signed in 1973, 1981, 1987,
1990 and 1991, respectively. In 1995, Pertamina extended its 1973 and 1981
long-term LNG sales contracts and signed agreements for two new long-term LNG
sales contracts. To supply the additional quantities of LNG called for primarily
by the 1973 contract extension, Pertamina is currently constructing a seventh
processing train at the Bontang LNG facility, the financing of which was
completed during 1995. The construction of the seventh train began in 1995, and
completion is expected in late 1997. Negotiations are also currently underway
for the construction of an eighth train to support the new sales contracts. The
Company is also participating in exploration activities of the East Kalimantan
joint venture, as well as exploration activities independent of that joint
venture in other parts of Indonesia.
The Company's principal properties in the North Sea are interests in the
Piper, Claymore, Saltire, Chanter, Scapa and Alba oil fields, the Sean gas
fields and the Britannia gas and condensate field. The Company owns a 20%
working interest in the Piper, Claymore, Saltire, Chanter and Scapa oil fields,
which are operated by Elf Enterprise Caledonia Limited and a 25% working
interest in the North, South and East Sean gas fields, which are operated by
Shell U.K. Limited. In 1995, the Company acquired a 15.5% working interest
1
<PAGE> 4
in Block 16/26, which includes the Alba field, for approximately $270 million.
The Alba field commenced production in 1994 and is operated by Chevron U.K.
Limited. As of December 31, 1995, the Company had recorded approximately 43
million barrels of oil as proved reserves for the Alba field. In 1994, the
Company also acquired a 9.42% unit interest in the Britannia gas field, a
portion of which underlies the Alba field, for approximately $159 million. The
Britannia field is operated by Britannia Operator Limited, a joint venture
between Conoco (U.K.) Limited and Chevron U.K. Limited. As of December 31, 1995,
the Company had recorded 46 million barrels of oil equivalent of proved
undeveloped reserves for the Britannia field. Production from the Britannia
field is expected to begin in late 1998.
Since 1977, the Company has participated through joint ventures in oil and
gas exploration, development and production in the Badin area in Pakistan. Oil
production from the Badin area began in 1982, and gas production began in 1989.
The Company is the operator of the Pakistan joint ventures with working
interests of either 30% or 25.5% in the currently producing fields. In 1995, the
Company signed a concession agreement for the Eastern Sindh block in
southeastern Pakistan, which covers approximately 1.8 million acres. The
Company, as operator, holds a 70% working interest in the concession.
The Company participates worldwide in exploration for oil and gas in both
new venture areas and the Company's producing areas. Current worldwide activity
includes interests in Alaska, Tunisia, Italy, Ireland and Argentina, as well as
the U.K., Pakistan and Indonesia.
In the United States, the Company operates the Geismar ethylene plant in
which it owns a 41.67% interest. Located near Baton Rouge, Louisiana, the
Geismar plant, which has a 1.25 billion annual gross pounds capacity (521
million net), processes gas liquids feedstocks to produce ethylene for sale to
several petrochemical manufacturers for the production of plastics used in
various consumer products.
In January 1996, the Board of Directors of the Company approved a $220
million capital expenditure budget for 1996. Approximately $152 million has been
budgeted for oil and gas development projects in the U.K. North Sea, Indonesia
and Pakistan, including $60 million for the continued development of the
Britannia field and $16 million for development activities at the Alba field.
The Company has also budgeted approximately $21 million for exploration projects
in the U.K. North Sea, Pakistan and Indonesia, $18 million for activities in
Alaska, including the Western Colville area on the North Slope, and $16 million
in new venture exploration activities primarily in Tunisia, Italy, Ireland and
Argentina. The Company has also budgeted approximately $10 million for its U.S.
petrochemical interests. Acquisition costs are not included in the capital
expenditure budget. See Item 7 -- Management's Discussion and Analysis of
Financial Condition and Results of Operation.
2
<PAGE> 5
SEGMENT DATA
The table below summarizes the Company's revenues, net income and
identifiable assets by areas of activity for the past three years(a):
<TABLE>
<CAPTION>
AS OF OR FOR THE
YEAR ENDED DECEMBER 31,
----------------------------
1995 1994 1993
------ ------ ------
(DOLLARS IN MILLIONS)
<S> <C> <C> <C>
Exploration and production:
Sales and operating revenues:
United Kingdom.............................. $ 323 $ 260 $ 208
Indonesia................................... 276 278 279
Pakistan.................................... 51 39 49
Other International......................... 1 1 1
------ ------ ------
Total............................. $ 651 $ 578 $ 537
====== ====== ======
Net income (loss):
United Kingdom.............................. 46 27 23
Indonesia................................... 95 94 89
Pakistan.................................... 14 10 16
Other International......................... (49) (25) (26)
United States (Alaska)...................... (6) (7) (34)
------ ------ ------
Total............................. $ 100 $ 99 $ 68
====== ====== ======
Identifiable assets:
United Kingdom.............................. 1,168 887 695
Indonesia................................... 459 473 476
Pakistan.................................... 46 40 37
Other International......................... 9 11 5
United States (Alaska)...................... 13 8 8
------ ------ ------
Total............................. $1,695 $1,419 $1,221
====== ====== ======
Petrochemicals:
Sales and operating revenues................... $ 200 $ 169 $ 145
Net income(b).................................. 38 15 5
Identifiable assets............................ 111 108 91
</TABLE>
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(a) Net income (loss) and identifiable assets do not give effect to general and
administrative items. See Note 13 of Notes to Consolidated Financial
Statements for additional data.
(b) Includes assumed U.S. taxes at regular statutory tax rates. The Company,
however, was subject to the U.S. corporate alternative minimum tax.
As reflected in the preceding table, a significant portion of the Company's
income was generated from its overseas operations, particularly its
participation in the producing fields in the East Kalimantan area of Indonesia
and in the U.K. North Sea. The Company's overseas operations are subject to
certain risks, including expropriation of assets, governmental reinterpretation
of applicable laws and contract terms, increases in taxes and government
royalties, renegotiation of contracts with foreign governments or customers,
foreign government approvals of lease, permit or similar applications and of
exploration and development plans, political and economic instability, disputes
between governments, payment delays, export restrictions, limits on allowable
levels of exploration and production and currency shortages, exchange losses and
repatriation restrictions, as well as changes in laws and policies governing
operations of companies with overseas operations, including more strict
environmental regulation. In addition, in the event of a dispute arising from
foreign operations, the Company may be subject to the exclusive jurisdiction of
foreign courts or may not be successful in subjecting foreign persons to the
jurisdiction of courts in the U.S. The Company may
3
<PAGE> 6
also be hindered or prevented from enforcing its rights with respect to a
governmental instrumentality because of the doctrine of sovereign immunity.
Foreign operations and investments may also be subject to laws and policies of
the U.S. affecting foreign trade, investment and taxation that could affect the
conduct and profitability of those operations. See "Current Markets for Oil and
Gas" below and Item 7 -- Management's Discussion and Analysis of Financial
Condition and Results of Operations.
All of the Company's oil and gas activities are subject to the risks
usually associated with exploration for, and development and production of, oil
and gas, including blowouts, cratering, oil spills, fires and adverse or
seasonal weather conditions. Offshore operations are also subject to marine
perils and extensive governmental regulations, as well as interruption or
termination by governmental authorities based on environmental or other
considerations. The Company's petrochemical operations are subject to certain
additional risks, including the breakdown or failure of equipment, the
performance of equipment at levels below those originally projected, and
explosions, fires, floods and other catastrophic events. The occurrence of any
of these events could cause injury to life or property, interruptions in
operations or increases in the costs of operations. As is customary in the oil
and gas and petrochemical industries, the Company reviews its safety equipment
and procedures and carries insurance against some, but not all, of these risks.
In particular, the Company's environmental insurance and pollution coverage
contain certain limitations in coverage. Losses and liabilities arising from
such events would reduce revenues and increase costs to the Company to the
extent not covered by insurance. See "Other Matters" below.
RESERVES
The following table sets forth information regarding the Company's
estimates of its proved net reserves as of December 31, 1995. The Company's
estimates of reserves filed with federal agencies, including the Securities and
Exchange Commission, agree with the information set forth below. For additional
information, see Note 17 of Notes to Consolidated Financial Statements.
<TABLE>
<CAPTION>
OIL EQUIVALENTS
OIL (MBBLS)(A)(B) GAS (MMCF)(B) (MBOE)(A)(B)
------------------------------- -------------------------------- --------------------------------
DEVELOPED UNDEVELOPED TOTAL DEVELOPED UNDEVELOPED TOTAL DEVELOPED UNDEVELOPED TOTAL
--------- ----------- ------- --------- ----------- -------- --------- ----------- -------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
United Kingdom......... 67,147 38,567 105,714 139,413 204,719 344,132 91,184 73,863 165,047
Indonesia(c)........... 17,041 1,901 18,942 758,942 139,432 898,374 147,893 25,941 173,834
Pakistan............... 3,215 1,168 4,383 58,642 62,780 121,422 13,325 11,993 25,318
Other International.... 19 19 19 19
------ ------ ------- --------- ------- --------- ------- ------- -------
Total.......... 87,422 41,636 129,058 956,997 406,931 1,363,928 252,421 111,797 364,218
------ ------ ------- --------- ------- --------- ------- ------- -------
Equity Partnership:
Indonesia(c)......... 6,926 785 7,711 307,102 57,977 365,079 59,875 10,781 70,656
------ ------ ------- --------- ------- --------- ------- ------- -------
Total.......... 94,348 42,421 136,769 1,264,099 464,908 1,729,007 312,296 122,578 434,874
====== ====== ======= ========= ======= ========= ======= ======= =======
</TABLE>
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(a) For the purpose of calculating reserves, oil includes condensate and for the
U.K., oil also includes natural gas liquids.
(b) Unless otherwise indicated in this Annual Report on Form 10-K, gas volumes
are stated at the legal pressure base of the area or country in which the
reserves are located and at 60 degrees Fahrenheit. As used herein, the term
"BTU" means British thermal unit, the term "TBtu" means trillion BTUs, the
term "MMBtu" means million BTUs, the term "Mcf" means thousand cubic feet,
the term "MMcf" means million cubic feet, the term "Bcf" means billion cubic
feet, the term "Tcf" means trillion cubic feet, the term "Bbl" means barrel,
the term "MBbls" means thousands of barrels, the term "MMBbls" means
millions of barrels, the term "boe" means barrel of oil equivalent, the term
"Mboe" means thousand barrels of oil equivalent and the term "MMboe" means
million barrels of oil equivalent. Gas is converted into a barrel of oil
equivalent based on 5.8 Mcf of gas to one barrel of oil. The term "LNG"
means liquefied natural gas and the term "LPG" means liquefied petroleum
gas.
(Notes continued on following page)
4
<PAGE> 7
(c) Information regarding Indonesian reserves relates to the Company's net
interest in a production sharing contract between the Indonesian joint
venture and Pertamina. The joint venture has no ownership interest in the
reserves but does have the right to share revenues and production and is
entitled to recover most field and other operating costs and capital
depreciation. The reserve estimates, which are based on year-end prices, are
subject to revision as product prices and costs fluctuate due to the cost
recovery feature under the production sharing contract. The impact on
reserves is inversely related to price changes and directly related to
changes in field operating and capital costs. In addition, reserve estimates
are subject to revision due to the effect that price fluctuations generally
have on estimates of recoverable reserves. Debt relating to the LNG
processing facilities owned by Pertamina is serviced from proceeds of LNG
sales prior to the distribution of such proceeds primarily to the members of
the joint venture, Pertamina and the other production sharing contractors.
The debt obligation is not the obligation of the joint venture. Debt service
relating to such facilities is accounted for in the Company's reserve
estimates as a cost of production and operation. Such debt service is
deducted in estimating future net revenues to be distributed among Pertamina
and the production sharing contractors, including the joint venture and the
Company's interest therein. See "International Exploration and
Production -- Indonesia" below and Note 17 of Notes to Consolidated
Financial Statements.
There are numerous uncertainties inherent in estimating quantities of
reserves and in projecting future rates of production and timing of development
expenditures, including many factors beyond the control of the producer. The
reserve data set forth in this Annual Report on Form 10-K represent only
estimates. Reserve engineering is a subjective process of estimating underground
accumulations of oil and gas that cannot be measured in an exact way, and the
accuracy of any reserve estimate is a function of the quality and quantity of
available data and of engineering and geological interpretation and judgment. As
a result, estimates of different engineers often vary. In addition, results of
drilling, testing and production subsequent to the date of an estimate may
justify revision of such estimate. Accordingly, reserve estimates at a specific
point in time are often different from the quantities of oil and gas that are
ultimately recovered, which differences may be significant. Additionally, the
estimates of future net revenues from proved reserves of the Company and the
present value of future net revenues are based upon certain assumptions about
future production levels, prices and costs that may not prove correct over time.
The meaningfulness of such estimates is highly dependent upon the accuracy of
the assumptions upon which they were based. See "Current Markets for Oil and
Gas" below.
In general, the Company's volume of production from oil and gas properties
declines with the passage of time. In addition, the Company's and its
co-venturers' participation share of gas volumes supplied to support Indonesian
LNG sales contract extensions or additions will be significantly less than their
participation share under the original long-term sales contracts. Except to the
extent the Company acquires additional properties containing proved reserves or
conducts successful exploration or development activities, or both, the proved
reserves of the Company, and the revenues generated from production thereof
(assuming no price increases), will decline as reserves are produced. Drilling
activities are expensive and subject to numerous risks, including the risk that
no commercially viable oil or gas production will be obtained. Increases or
decreases in prices of oil and gas and in cost levels, along with the timing of
development projects, will also affect revenues generated by the Company and the
present value of estimated future net cash flows from its properties. Revenues
generated from future activities of the Company are highly dependent upon the
level of success in acquiring, finding or developing additional reserves. See
Notes 1 and 17 of Notes to Consolidated Financial Statements.
The Company's reserve and production replacement strategy combines
exploitation, development drilling in proven areas and focused worldwide
exploration activities. The Company also continues to evaluate acquisitions to
add proved developed and undeveloped reserves with upside potential. The
Company's future oil and natural gas production is highly dependent on its level
of success in these activities, and there can be no assurance that such
activities will result in additional reserves and production. For a discussion
of the Company's production, see "International Exploration and Production"
below.
5
<PAGE> 8
PRODUCTION
The following table sets forth the Company's average daily production of
oil, natural gas liquids and gas during 1995, 1994 and 1993:
<TABLE>
<CAPTION>
EQUITY
UNITED PARTNERSHIP
KINGDOM INDONESIA PAKISTAN INDONESIA
------- --------- -------- -----------
<S> <C> <C> <C> <C>
Oil (MBbls per day):
1995................................................ 40 6 5 2
1994................................................ 35 6 5 2
1993................................................ 27 6 5 2
Natural gas liquids
(MBbls per day):
1995................................................ 2 1
1994................................................ 2 1
1993................................................ 1 1
Gas (MMcf per day):
1995................................................ 34 251(a) 45 83(a)
1994................................................ 24 266(a) 43 88(a)
1993................................................ 8 242(a) 43 80(a)
</TABLE>
- ---------------
(a) Includes gas consumed in the operation of the Indonesian LNG plant.
OIL AND GAS PRICES AND PRODUCTION COSTS
The Company's average sales prices and production costs of oil, natural gas
liquids and gas for 1995, 1994 and 1993 were as follows:
<TABLE>
<CAPTION>
EQUITY
UNITED PARTNERSHIP
KINGDOM INDONESIA PAKISTAN INDONESIA
------- --------- -------- -----------
<S> <C> <C> <C> <C>
Average sales prices:
Per Bbl of oil
1995.............................................. $16.14 $ 17.14 $14.24 $ 17.14
1994.............................................. 14.99 15.78 13.43 15.78
1993.............................................. 15.10 17.26 15.04 17.26
Per Bbl of natural gas liquids
1995.............................................. 10.92 18.11
1994.............................................. 9.46 17.56
1993.............................................. 10.38 17.89
Per Mcf of gas
1995.............................................. 2.78 2.90(a) 1.32 2.90(a)
1994.............................................. 2.57 2.72(a) 1.07 2.72(a)
1993.............................................. 2.49 3.00(a) 1.26 3.00(a)
Average production costs per boe(b):
1995.............................................. 5.05 3.02(c) 3.55 2.72(c)
1994.............................................. 5.56 3.06(c) 2.80 2.83(c)
1993.............................................. 7.68 3.49(c) 2.72 3.17(c)
</TABLE>
- ---------------
(a) Includes natural gas sold to fertilizer plants and a refinery. The average
sales price for LNG for 1995, 1994 and 1993 was $3.03, $2.85 and $3.17 per
Mcf, respectively.
(b) Primarily includes expenditures for operating expenses.
(c) Includes plant processing costs and debt service on the Indonesian LNG
processing facilities.
6
<PAGE> 9
CURRENT MARKETS FOR OIL AND GAS
Revenues generated from the Company's operations are highly dependent upon
the prices of and demand for oil and gas. The unsettled energy market makes it
difficult to estimate future prices and sales volumes of natural gas and crude
oil. Prices received by the Company for its oil and gas production are affected
by a number of factors beyond the control of the Company, including worldwide
supplies of oil and gas, changing international economic and political
conditions, contract enforceability, insolvency of other parties, domestic and
foreign energy legislation, weather, environmental conditions, regulations and
events, and actions of major petroleum producers including members of the
Organization of Petroleum Exporting Countries. The Company cannot predict
whether oil or gas prices will remain at, or increase or decline from, current
levels. If oil prices decline, the price for a significant portion of the
natural gas produced from the Company's properties, including the sales price
for LNG, will also decline.
ACREAGE
The following table summarizes the Company's developed and undeveloped
acreage at December 31, 1995, by geographic area. As used herein and in
"Drilling Activities" below, the term "gross" refers to acres or wells in which
the Company owns a working interest, and the term "net" refers to gross acres or
wells multiplied by the percentage of the working interest owned by the Company.
<TABLE>
<CAPTION>
DEVELOPED ACRES UNDEVELOPED ACRES
--------------- -------------------
GROSS NET GROSS NET
----- --- ------ ------
(NUMBERS IN THOUSANDS)
<S> <C> <C> <C> <C>
United States (Alaska)........................ 399 199
United Kingdom................................ 146 20 887 144
Indonesia..................................... 97 25 14,324 6,977
Pakistan...................................... 31 9 3,857 1,785
Other International........................... 12,948 7,384
--
--- ------ ------
Total............................... 274 54 32,415 16,489
=== == ====== ======
Equity Partnership:
Indonesia................................... 97(a) 11 1,046(a) 121
=== == ====== ======
</TABLE>
- ---------------
(a) The Company also has a direct interest in such gross developed and
undeveloped acreage, which is included above in the Company's gross acreage
for Indonesia.
DRILLING ACTIVITIES
At December 31, 1995, the Company's total gross and net productive oil and
gas wells, including multiple completions, by geographic area, were as shown in
the table below. The gross number of oil and gas wells with multiple completions
was 232.
<TABLE>
<CAPTION>
OIL WELLS GAS WELLS
------------------ ------------------
AREA GROSS NET GROSS NET
--------------------------------------------- ----- ------ ----- ------
<S> <C> <C> <C> <C>
United Kingdom............................... 64 12.31 22 4.05
Indonesia.................................... 74 18.60 382 92.95
Pakistan..................................... 42 12.47 51 14.90
Other International.......................... 1 .13
--- ----- ---- ------
Total.............................. 181 43.51 455 111.90
=== ===== ==== ======
Equity Partnership:
Indonesia.................................. 74(a) 8.19 382(a) 40.94
=== ===== ==== ======
</TABLE>
- ---------------
(a) The Company also has a direct interest in such wells, which is included
above in the Company's gross wells for Indonesia.
7
<PAGE> 10
The net productive and dry exploratory wells drilled during 1995, 1994 and
1993, by geographic area, were as follows:
<TABLE>
<CAPTION>
EXPLORATORY WELLS
-------------------------------------------------
PRODUCTIVE DRY
---------------------- ----------------------
AREA 1995 1994 1993 1995 1994 1993
----------------------------------------- ---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C>
United States (Alaska)................... .56 1.10
United Kingdom........................... .25 .73 .20 .80
Indonesia................................ .33 .26 1.29
Pakistan................................. 1.42 .56 1.11 1.63 1.11 1.76
Other International...................... 1.90 .75 1.05
---- --- ---- ---- ---- ----
Total.......................... 1.42 .81 1.11 4.59 2.88 6.00
==== === ==== ==== ==== ====
Equity Partnership:
Indonesia.............................. .11 .35
==== ====
</TABLE>
The net productive and dry development wells drilled during 1995, 1994 and
1993, by geographic area, were as follows:
<TABLE>
<CAPTION>
DEVELOPMENT WELLS
--------------------------------------------------
PRODUCTIVE DRY
----------------------- ----------------------
AREA 1995 1994 1993 1995 1994 1993
----------------------------------------- ---- ---- ----- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C>
United Kingdom........................... 1.36 1.20 2.80 .20
Indonesia................................ 3.90 5.59 6.83
Pakistan................................. .86 .60 1.20 .26 .60
---- ---- ----- --- --- ---
Total.......................... 6.12 7.39 10.83 .46 .60
==== ==== ===== === === ===
Equity Partnership:
Indonesia.............................. 1.72 2.47 3.01
==== ==== ===== === === ===
</TABLE>
At December 31, 1995, wells in progress were as follows:
<TABLE>
<CAPTION>
EXPLORATORY DEVELOPMENT
---------------- ----------------
GROSS NET GROSS NET
----- ---- ----- ----
<S> <C> <C> <C> <C>
United States (Alaska)........................... 7 1.47
United Kingdom................................... 13 1.40
Indonesia........................................ 1 .26 14 3.42
Pakistan......................................... 2 .51
-- --
---- ----
Total.................................. 10 2.24 27 4.82
== ==== == ====
Equity Partnership:
Indonesia...................................... 1(a) .12 14(a) 1.51
== ==== == ====
</TABLE>
- ---------------
(a) The Company also has a direct interest in such wells, which is included
above in the Company's gross wells for Indonesia.
At December 31, 1995, there were pressure maintenance programs in the U.K.
North Sea and in Pakistan.
INTERNATIONAL EXPLORATION AND PRODUCTION
Indonesia
The Company is engaged in oil and gas exploration, development and
production in Indonesia, primarily through a joint venture group it joined in
1969. Under a production sharing contract with Pertamina, the
8
<PAGE> 11
Indonesian national oil company, which currently covers approximately 1.1
million acres, the joint venture produces gas and, to a lesser extent, oil and
condensate, in the East Kalimantan area. Substantially all of the natural gas
produced by the joint venture is supplied, pursuant to long-term contracts with
Pertamina, to a liquefaction plant owned by Pertamina at Bontang Bay,
approximately 35 miles from the production areas. At the Bontang plant, gas is
converted into LNG in parallel processing units ("trains") by reducing the
temperature of the gas to approximately minus 161 degrees Celsius. The Bontang
plant currently has six trains in operation, and construction of the seventh
train by Pertamina is scheduled for completion in late 1997. Negotiations are
currently underway for an eighth train, the construction of which is expected to
begin in late 1997 or 1998. After conversion, the LNG is pumped into specially
designed tankers (owned by third parties) and transported to purchasers in the
Pacific Rim, where it is returned to its original gaseous form and used for fuel
by electric utilities and industry. The Bontang plant also processes LPG.
Production Sharing Contract and Drilling. The joint venture's production
sharing contract with Pertamina grants the joint venture the right to share in
the production and revenues from the contract area, but not ownership rights in
the oil and gas reserves. The joint venture's contract area in East Kalimantan
includes substantial portions of two fields, Badak and Nilam, as well as several
other fields. The joint venture has relinquished 20% of the area covered by the
production sharing contract since 1990 when the contract was extended and is
required to relinquish the following additional amounts of the area covered by
the contract: 10% by August 7, 1998, 10% by December 31, 2000, 15% by December
31, 2002, and 15% by December 31, 2004. The joint venture, however, is not
obligated to relinquish any area from which oil or natural gas is produced.
The production sharing contract originally expired in 1998, but in 1990,
Pertamina and the joint venture amended the production sharing contract and
extended the joint venture's right to explore, develop and produce oil and gas
in the contract area until 2018 through a second production sharing contract,
containing terms and conditions generally similar to the amended production
sharing contract. References herein to the production sharing contract mean the
production sharing contract in effect for the applicable time period. The
production sharing contract entitles the joint venture participants to recover
most field and other operating costs, as well as capital depreciation, and to
receive, net of Indonesian taxes, 35% of the remaining gas production until
August 1998, and 25% or 30%, depending upon the applicable sales contract, with
some exceptions, of such production for the remaining term of the contract. The
production sharing contract also entitles the joint venture participants to take
their respective shares of oil and condensate production in kind, and after
recovering operating expenses and capital depreciation, to retain 15% of the
proceeds from sales of such production, net of Indonesian taxes. Proceeds from
the sale of oil and condensate (except for that sold pursuant to the joint
venture's domestic market obligation) are currently based on official Indonesian
crude oil prices and reflect world market prices.
The Company owns a 37.81% working interest in the joint venture (26.25%
directly and 11.56% through subsidiaries of Unimar, the Equity Partnership). The
Company's 11.56% indirect interest is subject to the right of holders of
Unimar's Indonesian Participating Units ("IPUs") to receive a percentage of
certain cash flow resulting from Unimar's interest in the joint venture until
September 25, 1999, at which time the IPUs will expire with no residual value to
the holder. In 1995, approximately one-fourth of the Company's interest in such
cash flow of Unimar was burdened by such payment obligation. Virginia Indonesia
Company, a participant in the joint venture and a subsidiary of Unimar, acts as
operator of the joint venture. The vote of participants holding 66 2/3% of the
total joint venture ownership interest is generally required for approval of
significant matters pertaining to the joint venture.
At December 31, 1995, proved reserves (net) attributable to the Company's
total interest in the joint venture were approximately 1.3 Tcf of gas and 27
MMBbls of oil and condensate. The reserve estimates, which are based on year-end
prices, for the Company's net interest in the production sharing contract are
subject to revision as product prices and costs fluctuate due to the cost
recovery feature under the contract. The impact on reserves is inversely related
to price changes and directly related to changes in field operating and capital
costs. In addition, reserves are subject to revision due to the effect that
price fluctuations generally have on estimates of recoverable reserves. See Note
17 of Notes to Consolidated Financial Statements.
9
<PAGE> 12
Substantially all of the joint venture's natural gas production and
reserves are committed to several long-term supply agreements with Pertamina,
which obligate the joint venture to supply certain minimum quantities of natural
gas. The Company believes that there are adequate reserves in the joint
venture's production sharing contract area to supply natural gas under the joint
venture's contractual commitments outstanding as of December 31, 1995. Pertamina
continues to make progress in marketing additional LNG volumes. The percentage
of the natural gas supplied by the joint venture in support of future LNG or LPG
sales contracts, or renewals or extensions of existing long-term sales
contracts, is dependent primarily upon the uncommitted reserves of natural gas
that the joint venture has in its production sharing contract area at the time
that Pertamina establishes the allocation of the natural gas supply for such
sales contracts among the various contractor groups in the East Kalimantan area.
Because a substantial portion of the joint venture's reserves of natural gas has
been committed to support existing LNG sales contracts, the Company expects that
absent the discovery of significant additional natural gas reserves in the joint
venture's contract area, the joint venture's participation in future new sales
contracts for LNG and LPG, or in extensions or renewals of existing long-term
contracts, will be less than its current participation in existing contracts.
In 1995 and 1994, 16 and 23 successful development wells, respectively,
were drilled in fields in East Kalimantan. During 1996, the Company expects to
spend approximately $37 million on development projects. The joint venture also
continues to evaluate the East Kalimantan area to identify additional gas
prospects. All of these expenditures will be cost recoverable pursuant to the
production sharing contract.
The joint venture participants are required collectively to sell
approximately 8.5% of the total oil and condensate production from most existing
fields in the contract area at $0.20 per barrel for domestic Indonesian
consumption. The domestic market obligation is suspended, however, for the first
60 months of production from new fields in the contract area, after which the
price will be 10% of the realized Indonesian export price. These obligations are
factored into the Company's net reserves estimates. Each participant's remaining
oil and condensate production is generally sold in world oil markets. In
addition to the oil and condensate sold for domestic use, the joint venture
supplies gas for domestic consumption, and the amount supplied for such purposes
may increase or decrease in the future. Profits from gas supplied for domestic
consumption, which was sold at an average price of $1.07 per Mcf in 1995, are
less than from gas supplied for LNG. Gas supplied for domestic consumption
constituted less than 6% of the joint venture's gas production during 1995.
Bontang Plant. At the Bontang plant, natural gas supplied by the joint
venture and other production sharing contractors is converted to LNG and shipped
in LNG tankers ("cargoes"). These specially designed tankers vary in size and
the term "cargo" as used herein means 125,000 cubic meters of LNG. In 1995 and
1994, deliveries from the plant were 240 gross cargoes and 247 gross cargoes of
LNG, respectively. During 1993, the completion of the debottlenecking project on
the first four trains and the completion of the sixth train increased the
production capacity of the Bontang plant to approximately 275 gross cargoes per
year. The Bontang plant currently has additional unused processing capacity;
however, sales of LNG starting in 1998 under recently finalized sales contracts
will begin to use this excess capacity. See "Sales Contracts" below for more
information.
The amount of revenue that the Company receives as a result of the
production of natural gas in support of the sale of LNG by Pertamina is
dependent upon the number of cargoes shipped each year, the Company's ultimate
participation in each cargo, the price the buyers must pay for the LNG purchased
and the costs to be recovered from the proceeds of sales of LNG.
The Bontang plant's ability to manufacture and ship quantities of LNG is
dependent upon the continued operation of the Bontang plant without mechanical
failure and without the shutdown of any processing units in excess of scheduled
maintenance periods. The sale of LNG is also dependent upon the availability of
shipping without interruption and upon the continued operation of the buyers'
receiving terminals. The manufacture, shipment, receipt and distribution of LNG
can be interrupted or adversely impacted by severe weather, acts of nature or
other events. The costs associated with transportation of LNG, such as repair
and maintenance or replacement of LNG tankers, are beyond the control of the
Company.
10
<PAGE> 13
The Bontang plant is owned by Pertamina and operated on a
cost-reimbursement basis by a corporation owned in part by the joint venture.
The financing of the original two trains was repaid in 1990, and the financing
for the second two trains was repaid in 1993. Financing for construction of the
fifth train at the Bontang plant was provided principally from Japanese sources
through a funding arrangement under which debt service is paid by the Trustee
(as defined below) to the lenders from the proceeds of LNG sales, primarily
under the contract signed in 1987 with Chinese Petroleum Corporation ("CPC"),
the national oil company of the Republic of China (Taiwan). Final repayment is
scheduled in 2000. In 1991, Pertamina arranged $750 million under a similar
financing arrangement for the construction of the sixth train and associated
facilities at the Bontang plant. Construction began in 1991 and was completed in
late 1993 at a cost of approximately $700 million. Repayment began in 1994 from
proceeds of the Osaka contract (as defined below), and final repayment is
scheduled in 2004. In July 1995, a $969.5 million financing was completed for
the seventh train, third dock, LPG expansion and other support facilities. The
financing was provided from Japanese sources through arrangements similar to
those used to finance the Bontang plant's fifth and sixth trains. Repayment is
scheduled to begin in 1998 principally from the proceeds of the short-term LNG
sales contracts with CPC and Korea Gas Corporation ("KGC") and starting in 2000,
from the proceeds of the extension of the 1973 contract. The construction of the
seventh train began in 1995 and is currently scheduled for completion in late
1997. Financings of the fifth, sixth and seventh trains are nonrecourse to both
Pertamina and the joint venture.
Sales Contracts. The joint venture currently has gas supply agreements with
Pertamina that support the long-term and short-term LNG sales contracts and
obligate the joint venture to provide certain quantities of natural gas for
fulfillment of Pertamina's obligations pursuant to the LNG sales contracts. The
supply agreements terminate concurrently with the expirations of their
respective LNG sales contracts. The extent of the joint venture's obligation to
supply natural gas in support of Pertamina's LNG sales contracts and its right
to receive revenues attributable to the sale of LNG under such contracts vary
among the sales contracts. In 1995 and 1994, 99 Bcf and 108 Bcf, respectively,
net to the Company, were delivered to Pertamina under these supply agreements.
1996 is expected to represent a peak year for production for the joint venture.
LNG is currently sold by Pertamina to two groups of Japanese industrial and
utility customers and to CPC under long-term contracts signed in 1973, 1981 and
1987, respectively. Additionally, sales of LNG began in November 1994 under a
long-term contract signed in 1990 with a consortium of buyers organized by Osaka
Gas, a Japanese utility (the "Osaka contract"). LNG is also sold by Pertamina
under additional long-term contracts with KGC signed in 1983 and 1991 (the
"Korean Carryover" and "Korea II" contracts, respectively) and beginning in
1996, under the long-term Mid-Cities Gas Companies ("MCGC") contract signed in
1992. Some of the added capacity from the expansion of the LNG facilities during
1993 is also used to supply LNG sold under short-term contracts to Japanese,
Korean and Taiwanese buyers. The sales price under the LNG sales contracts is
tied to an average of prices for exported Indonesian crude oil.
In 1995, Pertamina finalized agreements to extend the LNG contracts
originally signed in 1973 and 1981 until 2010 and 2011, respectively. Pertamina
also signed agreements for two new long-term LNG sales contracts with CPC (Badak
VI) and KGC (Badak V), which provide for LNG sales from 1998 until 2017. To
support the supply of the additional quantities of LNG required primarily by the
1973 extended contract, Pertamina is currently constructing the seventh train.
In addition, Pertamina, the joint venture and the other production sharing
contract groups are currently planning the development, financing and
construction of an eighth train, which is anticipated to begin construction in
late 1997 or 1998, primarily to support the supply of quantities of LNG required
by the new CPC and KGC long-term contracts. The construction of the eighth
train, and accordingly the new CPC and KGC sales contracts in support thereof,
are subject to Indonesian governmental approval.
The Company's right to receive revenues from the sale of LNG and LPG under
any future new contracts or extensions or renewals of existing contracts,
including the 1973 and 1981 contract extensions and the new CPC and KGC
long-term contracts, is affected by the allocation of the gas supply obligation
in support of such contracts among the joint venture and the other production
sharing contractors supplying gas to the Bontang plant. This allocation is set
by Pertamina and is primarily based upon uncommitted reserves of natural gas
available at the time Pertamina makes the allocation. The allocation to the
Company's joint venture in such
11
<PAGE> 14
contracts has declined over time since the initial 1973 contract allocation at
97.9%, when the joint venture was virtually the only supplier to the Bontang
plant, to the present when there are two other major production sharing
contractors supplying gas to the Bontang plant and sharing in the allocation of
volumes. In 1995, Pertamina set the participation of the joint venture for most
of the quantities required by the 1973 contract extension and for certain years
of the new CPC and KGC long-term contracts at 21.6% based upon the joint
venture's uncommitted reserves as of May 31, 1994, which percentage is less than
the joint venture's participation in other existing LNG contracts. Pertamina has
not yet allocated among the joint venture and the other production sharing
contractors supplying natural gas to the Bontang plant the natural gas supply
obligation in support of the extension of the 1981 contract or the remaining
years of the new CPC and KGC long-term contracts; however, the Company expects
that the joint venture's participation will be less than 21.6%. A final
determination regarding the joint venture's participation percentage for a
portion of the 1981 extension and the remaining years of the new CPC and KGC
long-term contracts will be based upon reserves certified as of April 1995 and
is expected in 1996. A final determination for the last year of the 1973
extension and the rest of the 1981 extension is not expected before 1999.
Because the joint venture's participation percentage will be less, the joint
venture's and the Company's right to receive revenues attributable to the sale
of LNG under the extensions of the 1973 and 1981 contracts and the new CPC and
KGC long-term contracts will be less than that under the original contracts with
those buyers. The Company cannot predict the percentage participation that the
joint venture will have in other future contracts. The Company expects, however,
that absent the discovery of significant additional gas reserves in the joint
venture's contract area, the joint venture's percentage participation in such
future sales contracts will be less than that currently received. See the table
presented below for additional information.
The 1973 and 1981 contracts (including extensions thereof) and the CPC, CPC
(Badak VI), Osaka, Korean Carryover, Korea II, KGC (Badak V) and MCGC contracts
(collectively, the "long-term contracts") contain take-or-pay provisions that
generally require that the purchasers either take the contracted quantities or
pay for such quantities even if not taken. Prior to any extensions, the initial
term of each long-term contract is approximately 20 years. The other contracts
described in the table are short-term contracts and generally have a term of ten
years or less. Of the remaining LNG sales volumes to be delivered after December
31, 1995, under all of the contracts described in the table below, the long-term
contracts and the short-term contracts represent approximately 98% and 2%,
respectively, of such deliveries.
12
<PAGE> 15
The following table sets forth information regarding the Bontang LNG
plant's share of LNG sales contracts at December 31, 1995:
<TABLE>
<CAPTION>
JOINT
VENTURE'S
REMAINING SHARE OF
LNG REMAINING
SALES LNG SALES
CONTRACT VOLUMES JOINT VENTURE VOLUMES
TERM (TBTU) PARTICIPATION % (A)(B) (TBTU) (C)
---------- ----- ---------------------- ----------
<S> <C> <C> <C> <C>
LONG-TERM:
1973............................... 1977-1999 704 97.9/27.2 374
1973 Extension..................... 2000-2010 4,797 (d) (d)
1981............................... 1983-2003 1,364 66.4/29.6 859
1981 Extension..................... 2003-2011 1,470 (e) (e)
CPC................................ 1990-2009 1,221 29.6 361
CPC (Badak VI)..................... 1998-2017 1,729 (f) (f)
Osaka.............................. 1994-2013 2,154 27.2 586
Korean Carryover................... 1986-2006 159 50.0 79
Korea II........................... 1994-2014 918 27.2 250
KGC (Badak V)...................... 1998-2017 1,062 (f) (f)
MCGC............................... 1996-2015 361 27.2 98
SHORT-TERM:
Toho............................... 1988-1999 40 29.6/27.2 12
KGC MOA............................ 1995-1999 279 21.6 60
CPC MOA............................ 1998-1999 46 21.6 10
</TABLE>
- ---------------
(a) The joint venture's participation percentage is set by Pertamina based upon
uncommitted reserves of the various production sharing contractors
supplying gas to the Bontang plant. The participation percentages
determined by Pertamina apply to new contracts, or amendments or extensions
of contracts, entered into during certain time periods. During 1995,
Pertamina set the joint venture's participation percentage at 21.6%, based
upon the joint venture's uncommitted natural gas reserves certified as of
May 1994, for the 2000-2009 period of the extension of the 1973 contract,
the first two years of the CPC (Badak VI) and KGC (Badak V) contracts and,
in general, for sales of LNG during the period from 1994 to 1999 under new
contracts or renewals or extensions of existing contracts. Pertamina has
not yet established the joint venture's participation percentage in the
first five and a half years of the 1981 extension or the 2000-2017 period
of the CPC (Badak VI) and KGC (Badak V) long-term contracts; however, the
Company expects the percentage to be less than 21.6%. The Company expects a
final determination from Pertamina in 1996. For other future sales
contracts, including the remaining term of the 1981 extension and the final
year of the 1973 extension, the Company cannot predict the participation
percentage of the joint venture in such contracts, although absent the
discovery of significant additional gas reserves in the joint venture's
contract area, the participation percentage is expected to be less than
21.6%.
(b) Those contracts that show two joint venture participation percentages have
been amended or extended to provide for additional deliveries. The second
percentage indicates the portion of gas to be supplied under the amendment
or extension of such contract by the joint venture. The joint venture has a
97.9% and 27.2% interest in 258 and 446 remaining TBtus, respectively, of
the total 704 TBtus remaining to be sold under the 1973 contract; a 66.4%
and 29.6% interest in 1,238 and 126 remaining TBtus, respectively, of the
total 1,364 TBtus remaining to be sold under the 1981 contract; and a 29.6%
and 27.2% interest in 26 and 14 remaining TBtus, respectively, of the total
40 TBtus remaining to be sold under the Toho contract.
(c) The joint venture's share of remaining LNG sales volumes represents volumes
available to the joint venture under the sales contracts for servicing its
share of plant operating and debt service costs, as
(Notes continued on following page)
13
<PAGE> 16
applicable, for recovering exploration, development and production costs
and for profit sharing between the joint venture and Pertamina.
(d) As discussed in footnote (a) above, the joint venture's participation in
the 1973 extension is 21.6% for the period 2000-2009. The joint venture's
share of the contracted volumes for such period is 942 TBtus.
(e) As discussed in footnote (a) above, the joint venture's participation in
the 1981 extension has not been determined by Pertamina.
(f) As discussed in footnote (a) above, the joint venture's participation in
the CPC (Badak VI) contract and KGC (Badak V) contract is 21.6% for the
period 1998-1999. The participation percentage for the contract years 2000
and beyond has not been determined by Pertamina. The joint venture's share
of the contracted volumes under the CPC (Badak VI) and KGC (Badak V)
contracts for the period 1998-1999 is 9 TBtus and 22 TBtus, respectively.
In general, the processing and operating costs of the Bontang plant are
charged to each LNG and LPG sales contract during each year based upon the ratio
of the sum of BTUs of LNG and LPG processed by the Bontang plant for each
contract to the total number of BTUs processed by the Bontang plant.
Under the 1973, extended 1973, extended 1981, Korean Carryover, MCGC, CPC
and CPC (Badak VI) long-term contracts and, in general, the short-term
contracts, LNG is sold on a delivered basis (i.e., title and risk of loss do not
pass until the LNG is unloaded at the customers' facilities). Under the 1981,
Osaka, Korea II and KGC (Badak V) contracts, LNG is delivered F.O.B. (i.e.,
title and risk of loss pass upon loading at Pertamina's port facility). Payments
for LNG under all of the LNG sales contracts are, or will be, made by the
purchasers in U.S. dollars directly to a bank in the United States that acts as
trustee and paying agent (the "Trustee") with respect to sales proceeds. Bontang
plant processing fees, debt service with respect to plant financings,
transportation (as required) and other costs are deducted from sales proceeds,
and the balance is then distributed to Pertamina, the members of the joint
venture and the other production sharing contractors.
At December 31, 1995, the average LNG price under all contracts supplied
from the Bontang plant was $2.83 per MMBtu, or $3.13 per Mcf. Prices under the
contracts are subject to monthly adjustments. As of December 31, 1995, January
31, 1996, and March 1, 1996, the average price for the group of crude oils used
to determine the price of LNG was $18.16, $19.10 and $18.70 per Bbl,
respectively. The Company is unable to predict the amount or timing of future
changes in the price of this group of crude oils. Every $1.00 change in the
average of the price of this group of crude oils results in approximately a
$0.17 per Mcf change in the price of LNG.
Pertamina also sells LPG produced at the LPG processing facilities at the
Bontang plant under seven contracts with Japanese purchasers, each of which is
for a ten-year term. The Bontang plant delivers an aggregate of up to 800,000
metric tons of LPG (5.9 MMboe) per year to support these contracts. The joint
venture currently has 29.6% and 21.6% participations in the gas processed at the
Bontang plant to supply quantities of LPG to be sold under the LPG contracts.
Pertamina may from time to time sell quantities of LPG outside of the seven LPG
contracts, and to the extent that such sales are made, the joint venture
currently will have a 21.6% participation in the gas processed at the Bontang
plant to supply those additional sales. A significant portion of the LPG sales
proceeds from sales under the seven contracts is dedicated to the repayment of
financing of the LPG processing facilities at the Bontang plant.
U.K. North Sea
The Company's principal U.K. North Sea properties include interests in the
Piper, Claymore, Saltire, Chanter, Scapa and Alba oil fields, the Sean gas
fields and the Britannia gas and condensate field. The Company also owns a 20%
interest in the Flotta terminal and pipeline system located in the Orkney
Islands in Scotland.
Piper and Claymore Fields. In 1971, the Company joined a consortium of
companies, of which Elf Enterprise Caledonia Limited is now the operator, to
explore for oil and gas in certain areas of the North Sea. The Company has a 20%
working interest (17.5% revenue interest after government royalty) in the Piper
and Claymore fields discovered in 1972 and 1974, respectively. Production from
Piper and Claymore originally
14
<PAGE> 17
began in late 1976 and late 1977, respectively and after being shut down in July
1988, Claymore recommenced in 1989, and Piper recommenced in 1993 from a new
fixed platform ("Piper B"). Oil production from the fields is transferred 135
miles via the joint venture's pipeline to the Flotta terminal. The proved
reserves (net) as of December 31, 1995, contained in the Piper and Claymore
fields are 17 MMboe and 19 MMboe, respectively. Average daily production of oil
and liquids (net to the Company) for 1995 from the Piper and Claymore fields was
16 MBbls and 8 MBbls, respectively.
In 1995, construction and installation of a new platform to provide
personnel accommodation facilities for the Claymore field were completed. The
new facilities replaced accommodations on the Claymore A production platform and
a floating unit that was moored alongside. The Company's total share of the cost
of this new platform from the project's inception in 1992 to its completion in
1995 was $36 million, including $9 million spent in 1995. The costs of the
platform were fully deductible in the year incurred for purposes of determining
the U.K. Petroleum Revenue Tax ("PRT") payable with respect to production from
the Claymore field.
The Piper and Claymore fields are currently subject to PRT at a 50%
statutory rate, which is based on the net value of oil and gas produced from
each field and on pipeline tariffs. The U.K. tax structure has encouraged
development of smaller fields in the northern North Sea by exempting all or part
of their production from PRT. These fields, such as the Saltire, Chanter and
Scapa fields described below, are referred to as edge oil fields because they
generally have separate field designations, incur little or no PRT, have no
government royalty interest burden and are developed as satellites from an
existing platform. It is anticipated that only small amounts of PRT, if any,
will be paid on the production from these fields. Production exempted from PRT
provides a greater contribution to cash flow on a per-barrel basis. All
production is subject to the U.K. corporation tax, which is at the current rate
of 33% (27.5% effective rate after benefits provided by the U.K./U.S. tax
treaty). Under current U.S. tax law, the PRT and U.K. corporation tax may be
credited against U.S. taxes.
Saltire Field. The Company has a 20% working and revenue interest in the
Saltire field, which was discovered by the joint venture in 1988. The Company
developed Saltire using a fixed platform connected subsea to the Piper B
platform. The Saltire platform was completed and production began in May 1993.
Average daily production (net to the Company) for 1995 was 9 MBbls of oil and
liquids. Proved reserves (net) at December 31, 1995, for Saltire were 9 MMboe.
Chanter Field. The Company has a 20% working and revenue interest in the
Chanter field, which is comprised of two reservoirs, one oil and the other
natural gas and condensate. Production from the Chanter field began in May 1993.
The Chanter field was developed as a subsea satellite to the Piper B platform.
Average daily production (net to the Company) for 1995 was 1 MBbl of oil and
liquids. The proved reserves (net) contained in the field are 2 MMboe as of
December 31, 1995.
Scapa Field. The Scapa field, in which the Company has a 20% working and
revenue interest, was discovered in 1975 and is produced using a subsea
production facility tied to the Claymore platform. Average daily production (net
to the Company) for 1995 was 3 MBbls of oil and liquids. Proved reserves (net)
at December 31, 1995, for the Scapa field were 6 MMboe of oil.
Alba Field. In July 1995, the Company acquired from Oryx U.K. Energy
Company ("Oryx") a 15.5% working and revenue interest in the central U.K. North
Sea's Block 16/26, which includes the Alba oil field, for approximately $270
million. Oil is pumped from a platform located in the northern portion of the
Alba field to a permanently moored floating storage unit three miles away. A
dedicated shuttle tanker transports oil to refineries in the U.K. and Europe. At
year-end, proved reserves (net) for the Alba field were 43 MMBbls of oil, of
which 23 MMBbls are classified as proved undeveloped. The Company anticipates
recording additional proved reserves based on the field's production history and
future development activity. The Alba field, which commenced production in
January 1994, is expected to produce for over 20 years. Average daily production
(net to the Company) for the last six months of 1995 was 11 MBbls of oil.
Chevron U.K. Limited operates the field. Revenues from the Alba field are
subject to U.K. corporation tax, but are not subject to U.K. royalty. The
Company anticipates that only small amounts of PRT will be paid on the Company's
production.
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Sean Fields. The Company has a 25% working interest (24.375% revenue
interest after overriding royalty) in the Sean gas development project,
discovered in 1969 in the southern portion of the U.K. North Sea. The project,
operated by Shell U.K. Limited, consists of the North, South and East Sean
fields. The proved reserves (net) as of December 31, 1995, contained in the
fields were 23 MMboe.
The Sean platforms, which currently serve the North, South and East Sean
fields, made their first deliveries in December 1986. Under the terms of a gas
sales contract terminating in 2011 with British Gas plc, ("BG") the Company will
deliver, during each winter contract period, an average minimum of 3.1 Bcf (net
to the Company) from the North and South Sean fields, up to the maximum field
contractual reserve of 425 Bcf (104 Bcf net to the Company). This peak-shaving
gas sales agreement also provides that currently proved gas reserves from the
North and South Sean fields may be sold only to BG. The price under the gas
sales agreement is based upon the volume of gas taken and various U.K. price
indices. The average price for 1995 was $3.37 per Mcf. The Company also earns a
capacity charge during the fall and winter months, which is independent of
production levels, to ensure field deliverability of 600 MMcf (gross) per day.
The capacity charge for 1995 totaled $35 million (net to the Company), and the
revenue for the volume of gas taken on 26 days of production was $13 million
(net to the Company). The Company anticipates that, at current production
levels, only small amounts of PRT will be paid over the next few years with
respect to the Company's production from the North and South Sean fields.
Discovered in 1994, the East Sean field is separated from the producing
reservoirs of the North and South Sean fields, and as a result, production from
the East Sean field is not subject to the peak-shaving contract with BG. The
majority of the Company's share of gas from the East Sean field, which produces
year-round, is sold to Alliance Gas Limited under a short-term contract; the
balance is sold on the spot market. 1995 marked the first full year of
production from the field, which averaged 11,500 Mcf (net) per day. The Company
also participated in 1995 in two wells to test structures adjacent to the East
Sean field, one of which was successful. Production from the East Sean Field is
not subject to PRT.
Britannia Field. In 1994, the Company acquired a 9.42% unit interest in the
undeveloped Britannia natural gas and condensate field, a portion of which
underlies the Alba field, in the U.K. North Sea from Fina Exploration Limited
and Fina Petroleum Development Limited, subsidiaries of Petrofina SA. The
purchase price was $159 million. The Company's total share of development costs
for its interest in the Britannia field is estimated to be approximately $200
million, at current exchange rates, over a five-year period from 1994 to 1998.
As of December 31, 1995, the Company has spent $34 million, of which $31 million
was spent in 1995, for drilling activities and initial platform fabrication and
facilities work and expects to spend approximately $60 million in 1996. The
Britannia field is operated by Britannia Operator Limited, a joint venture
between Conoco (U.K.) Limited and Chevron U.K. Limited. Production from
Britannia is expected to begin in late 1998. Long-term agreements have been
reached to sell a substantial portion of the gas production in the U.K. market
to four purchasers: Kinetica Limited, Mobil Gas Marketing (U.K.) Limited,
National Power plc and Total Gas Marketing Limited. The gas production will be
processed at the SAGE terminal in St. Fergus in northeastern Scotland, which
will be expanded by the SAGE owners to accommodate the Britannia production. A
pipeline will be constructed to transport the production from Britannia to the
SAGE terminal. As of December 31, 1995, proved undeveloped reserves (net) for
the Britannia field were 46 MMboe, reflecting upward reserve revisions recorded
during 1995 of 8 MMboe. Revenues from the Britannia field will be subject to the
U.K. corporation tax, but will not be subject to U.K. royalty or PRT.
Customers. For 1995, the Company's U.K. operations had crude oil sales at
prevailing market prices to B.P. Oil International Limited and Elf Trading, two
major international oil and gas companies, equal to 13% and 13%, respectively,
of the Company's total sales and operating revenues. Because of the broad market
for crude oil in the U.K., the Company believes that the loss of these customers
would not have a material adverse effect on the Company. See Note 12 of Notes to
Consolidated Financial Statements. BG has publicly indicated a strategy to
renegotiate its gas purchase agreements with producers in the U.K. Also, BG has
announced a proposed corporate reorganization to transfer BG's gas supply
business into a new subsidiary, which the Company believes will include the
Piper and Sean purchase agreements. The Company cannot predict what effect, if
any, such actions will have on the Company.
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Other Information. Production from the Company's interest in the U.K.
fields totaled 17 MMboe during 1995, an increase of 16% from 1994. With a
full-year production from the Alba field, the Company expects a modest increase
in this 1995 production level for 1996 despite anticipated production declines
from certain U.K. fields. Payment to the Company with respect to oil production
from the Piper, Claymore, Saltire, Chanter, Scapa and Alba fields is made in
U.S. dollars, and payments for gas production including under the Sean gas sales
agreements with BG and Alliance Gas Limited are made in pounds sterling. There
are no significant restrictions on the repatriation of funds from the Company's
U.K. subsidiary to the United States. Dividends paid to the Company by its U.K.
subsidiary are subject to a 25% U.K. advance corporation tax. Approximately
27.5% of this tax (or approximately 6.9% of the dividend paid) is available for
immediate refunding to the Company by the U.K. government. All of this tax
(including the refunded portion) may be credited against the U.K. corporation
tax paid by the Company's U.K. subsidiary.
For additional information, see Item 7 -- Management's Discussion and
Analysis of Financial Condition and Results of Operation.
Pakistan
Badin Concessions
Since 1977, the Company has participated through joint ventures in the
exploration for, and development and production of, oil and gas in the Badin
area of the Sindh Province in southeastern Pakistan. The Company's activities
are conducted under three concession agreements.
1977 Concession. In April 1977, the Pakistan government granted exploration
rights in the Badin area to the Company and its co-venturers (the "1977
concession" or the "Badin-I concession"). The Company is the operator of a joint
venture that includes the Oil and Gas Development Corporation, a Pakistan
government-owned company. The oil and gas reserves discovered under the 1977
concession continue to be produced under leases granted by the Pakistan
government. The terms of such leases are 30 years from the date that they were
first granted. The Company has a 30% working interest (26.25% revenue interest)
in the 1977 concession area.
1992 Concession. In 1992, the joint venture was granted a three-year
extension of the exploration license that it originally received in 1977 (the
"1992 concession" or the "Badin-II concession"). The oil and gas reserves
discovered under the 1992 concession will be produced under 20-year leases
granted by the Pakistan government. Production from the 1992 concession began
during 1995. The Company has a 25.5% working interest (22.3% revenue interest)
in the 1992 concession area.
1995 Concession. The exploration license granted by the Pakistan government
in 1992 under the Badin II concession expired in January 1995. In December 1994,
the joint venture and the Pakistan government signed a new petroleum concession
agreement (the "1995 concession"). The 1995 concession provides that the
exploration license will be extended for three one-year periods beginning
January 1995, subject to satisfying certain minimum work requirements. The 1995
concession also provides that the Company will act as operator and will bear 38%
of the costs of exploration, including 12.5% attributable to the Pakistan
government. Under the 1995 concession, the Company will explore for and develop
oil and gas on the approximately 1.6 million acres in the Badin area not covered
by leases granted under the 1977 concession or the 1992 concession. As
discoveries are made, the joint venture will apply for individual 20-year leases
in which the Company will have a 25.5% working interest (22.3% revenue
interest), provided the Pakistan government elects to exercise its option to
increase its working interest in each such discovery to 25%.
The Pakistan government is contractually obligated under the 1992 and 1995
concession agreements to issue leases upon the determination of a commercial
discovery and the fulfillment by the joint venture of the conditions of the
concession agreements and the exploration license.
Proved reserves (net) at December 31, 1995, for the Company's interest in
the Badin concessions were 4 MMBbls of oil and 121 Bcf of gas. The joint venture
under the 1977 and 1992 concessions produced approximately 37% of Pakistan's
total domestic oil output and 10% of the country's gas production in 1995.
Average daily production (net to the Company) during 1995 was 5 MBbls of oil and
45 MMcf of gas. The Company's share of the oil produced from the 1977 and 1992
concessions is sold for both Pakistan domestic
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<PAGE> 20
use and for export. The price received for oil sold domestically is tied to the
average spot market price of Middle Eastern crude oil. In 1995, the Company
supplied 1 MMBbl of oil (net to the Company) for export at prices based on
competitive spot market rates. The Company and its co-venturers sell natural gas
produced from the 1977 concession area to Sui Southern Gas Company, Ltd.
("SSGC"). The contract expires in 2003 and provides that SSGC must either take
or pay for the contracted quantities of natural gas. Natural gas produced from
the 1992 concession area is also sold to SSGC under a contract with terms
similar to the SSGC contract covering production from the 1977 concession.
During 1995, the Company drilled 12 exploratory wells in the Badin
concessions, five of which were discoveries. The discoveries included three gas
fields, one oil and gas field and one oil field. During 1996, the Company plans
to drill up to seven exploration wells and nine development wells in the Badin
concessions.
Eastern Sindh Concession
In April 1995, the Company signed a concession agreement with the Pakistan
government covering approximately 1.8 million acres in the Eastern Sindh block
in the Sindh Province of southeastern Pakistan for which the Company was granted
an exploration license in December 1994. The concession agreement and the
exploration license provide the Company with the right to explore for oil and
gas for an initial period of three years, with an option for three extensions of
one year each, and upon a commercial discovery, the right to apply for a 20-year
lease with the Pakistan government. The Company is the operator and has a 70%
working interest in the concession and exploration license, which is subject to
reduction if the Pakistan government elects to participate upon discovery of
commercial production. During 1996, the Company plans to conduct seismic and
other geological and geophysical studies on this concession.
Other International
In addition to the activities described above, the Company conducts
evaluations as well as undertakes exploration activities worldwide to expand its
reserve base. The Company has budgeted approximately $21 million during 1996 for
exploration projects in the U.K. North Sea, Indonesia and Pakistan. The Company
has also budgeted a total of $16 million for exploration activities during 1996
in other international areas, including primarily the activities described
below. See Item 7 -- Management's Discussion and Analysis of Financial Condition
and Results of Operations. The Company is also pursuing the possibility of
investing in downstream opportunities in Pakistan and Indonesia, including
electrical power generation and LPG projects.
Italy. In 1995, the Company acquired interests in three onshore exploration
permits covering approximately 216,000 acres in the Basilicata Region in
southern Italy. The Company serves as operator of and holds a 42% working
interest in the Serra Corneta permit. The Company also holds a 33.33% working
interest in the Tempa dei Mercanti permit, operated by Edison Gas, and a 20%
working interest in the Forenza permit, operated by LASMO International Limited.
Geological and seismic studies on the three permit areas were conducted in 1995
and will continue in 1996. The Company has also filed an application with the
Italian government for an additional exploration permit near the Serra Corneta
and Tempa dei Mercanti permit areas.
The Company also entered into an agreement in 1995 to acquire a 20% working
interest in the onshore Baragiano permit, which covers about 93,000 acres in the
Basilicata region, from Enterprise Oil Exploration Ltd. ("Enterprise"), subject
to approval by the Italian government. Enterprise serves as operator, and the
permit's first exploration well is scheduled to begin the first half of 1996.
Tunisia. In 1993, the Company obtained an oil and gas exploration permit
offshore Tunisia from the Government of Tunisia. The permit calls for a
four-year exploration program on the approximately one-million-acre Ramla block.
The block is situated about 80 miles offshore in the Gulf of Gabes,
approximately 140 miles southeast of the city of Tunis. The Company serves as
operator and bears 50% of the exploration costs. In the event of a commercial
discovery, the Tunisian national oil company has the right to participate for up
to a 50% working interest. The permit may be extended for an additional
four-year term under certain conditions. The Company drilled a well on the Ramla
block in 1995 which found a significant oil column and an active hydrocarbon
system, but poor reservoir quality at that location made the accumulation non-
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commercial. In December 1995, the Company acquired additional seismic on the
block. One additional exploration well is planned for late 1996.
In 1994, the Company also acquired a 65% working interest in the onshore
Jeffara exploration permit, which covers approximately 970,000 acres in the
Medenine Region of southeastern Tunisia. The Company's interest is subject to
the Tunisian national oil company's right to participate for up to a 50% working
interest in the event of a commercial discovery. The Jeffara exploration permit,
which is operated by the Company, has an initial three-year term expiring in
1996, with an optional two-year extension. The initial exploratory well drilled
in 1995 was plugged and abandoned. During 1996, the Company will study seismic
and drilling information and other data to determine whether to exercise its
option to extend the permit by future drilling.
Eastern Indonesia. In Eastern Indonesia, the Company is the operator of
four production sharing contracts originally covering approximately 13 million
acres in the Maluku (Moluccas) Island group in the Banda Sea. At year-end, the
Company held a 60% working interest in the Tanimbar and Rebi production sharing
contracts and a 33.33% working interest in the Kai and Barakan production
sharing contracts, following the transfer of a 26.67% working interest in the
Kai and Barakan contracts to a third party during 1995. The initial exploration
well drilled during 1995 in the area was unsuccessful. In 1996, the Company
plans to relinquish all but the Kai contract, retaining about 4.6 million acres,
and drill a well in such contract area. The Company also expects to increase its
interest in the Kai contract to 44.44%.
Argentina. The Company serves as operator and has a 50% working interest in
the Cuenca Colorado Marina-1 ("CCM-1"), located in the South Atlantic Ocean
about 310 miles south of Buenos Aires. The exploration permit granted by the
Argentine government currently extends until August 1997 and provides the
Company with the option to extend the term of the agreement until 2001 by
meeting certain additional drilling obligations. An additional two-year
extension to 2003 is possible if the Company elects to drill one well for each
year of the extension. The initial exploratory well drilled in 1994 on the CCM-1
block was unsuccessful, as were the two additional wells drilled in 1995. During
1996, the joint venture intends to acquire new seismic data and study results
from these wells to determine future drilling plans. In February 1996, the
Company relinquished 50% of the CCM-1 block, leaving 2.2 million acres under the
permit.
Ireland/England. In 1995, the Company acquired a 25% working and revenue
interest in five and one-half offshore blocks encompassing 194,000 acres in St.
George's Channel offshore Ireland operated by Marathon Oil Company ("Marathon").
An initial exploratory well drilled in 1995 was unsuccessful. The joint venture
expects to study the results from this well to determine future drilling plans.
The Company also acquired in 1995 a 15% working and revenue interest in a
joint venture that was awarded eight offshore blocks covering 400,000 acres in
St. George's Channel offshore Western England operated by Marathon. This acreage
contains a small gas discovery and is complementary to the acreage described
above offshore Ireland. The joint venture drilled one exploratory well in 1995,
which was unsuccessful. The joint venture plans to drill two additional wells in
late 1996 or 1997.
In 1995, the Company also acquired a 15% working and revenue interest in
five and one-half blocks, covering 344,000 acres in the Porcupine basin,
offshore southwest Ireland. The joint venture, operated by Statoil (U.K.) Ltd.
("Statoil"), was granted a license to explore for oil and natural gas for a
15-year period, subject to certain minimum work requirements during each
four-year period. In 1994, the Company acquired a 30% working and revenue
interest in a joint venture that was awarded 11 blocks offshore Ireland. The
blocks cover 650,000 acres and are located in the Atlantic Ocean about 43 miles
west of Ireland in the Slyne/Erris basins. The joint venture, operated by
Statoil, was granted the right to explore for oil and natural gas for a 16-year
period, subject to certain minimum work requirements at four-year intervals.
During the initial terms of the Slyne/Erris and Porcupine exploration licenses,
each joint venture plans to acquire seismic data as well as conduct additional
geological and geophysical studies. After the acquisition of the seismic data
and the performance of other studies, each joint venture will determine whether
the geology warrants drilling any wells and continuing its respective license.
Australia. The Company entered into an agreement in 1995 to acquire an 80%
interest in 81 blocks covering 1.6 million acres in the Canning Basin of Western
Australia. The initial exploration period of the
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permit expires in April 1998. During 1996, the Company plans to acquire seismic
data to determine whether to exercise its option to drill an exploratory well to
retain its interest.
Other. The Company also has interests in oil and gas exploration activities
in Papua New Guinea and Vietnam.
ALASKA
The Company also pursues exploration projects in Alaska. At year-end 1995,
the Company held acreage primarily in Western Colville, the Kenai Peninsula and
offshore the Beaufort Sea in Alaska.
Western Colville. Since 1992, the Company has participated in exploration
drilling activities in the Western Colville area on Alaska's North Slope, in
which the Company currently has a 22% working interest. During the 1995 winter
drilling season, the Company participated in the completion of five wells, of
which three were sidetracks. The Company believes that geologically recoverable
oil reserves have been identified by well penetrations in this area (including
the wells drilled during 1995 and in prior years), and that based on the results
of the 1995 winter drilling season, additional reserves could be found by future
drilling on the Company's leasehold. The Company anticipates that further
delineation drilling and engineering studies will need to be conducted before
commercial development would be possible. The Company expects to participate in
three to six delineation and exploration wells to be drilled during the 1996
winter drilling season and a 100 square mile 3-D seismic survey. ARCO Alaska,
Inc. is the operator of the Colville venture.
Kenai Peninsula. Effective November 1, 1993, the Company entered into a
three-year exploration agreement with Cook Inlet Region, Inc. ("CIRI"), an
Alaska Native Regional Corporation. The agreement includes an initial option to
the Company to lease approximately 340,000 acres in the Kenai Peninsula in south
central Alaska. Under the agreement, the Company will bear 100% of the
exploration costs and may acquire leases on prospects identified, subject to
CIRI's option to participate in the leases and the exploration, drilling and
development of such prospects. As of March 1, 1996, the Company has exercised
options to lease approximately 18,700 acres and has a remaining option to lease
about 50,600 acres expiring on November 1, 1996. In 1995, the Company was also
awarded leases on 17 blocks onshore and offshore the Kenai Peninsula acquired in
a 1994 lease sale held by the State of Alaska. The Company also acquired 7
onshore blocks in the Kenai Peninsula in a 1995 lease sale, which were awarded
in February 1996. CIRI has an election to acquire a 20% working interest in such
leases under the terms of the exploration agreement. During 1995, the Company
interpreted seismic data, conducted geochemical and gravity field studies and
completed final mapping of several geologic horizons on its Kenai acreage. The
Company plans to evaluate seismic data and conduct other geochemical and
geophysical evaluations of the area during 1996. Drilling on the Kenai acreage
is scheduled to commence in late 1997 or 1998.
Kuvlum. The Company holds 100% working interest in the Kuvlum federal
exploratory oil and gas unit in the Beaufort Sea offshore Northern Alaska for
further analysis. In 1993, the Company determined that the Kuvlum unit was not
commercial as a stand-alone development. See Item 7 -- Management's Discussion
and Analysis of Financial Condition and Results of Operations.
PETROCHEMICALS
Plant Operations. The Company's petrochemical business consists primarily
of the Company's 41.67% interest in the jointly owned Geismar ethylene plant
located on the Mississippi River near Baton Rouge, Louisiana. The plant began
operations in 1968. The Company operates the plant, with production costs and
plant production being shared by the co-owners according to their ownership
interests. With the start-up of the twelfth furnace at the plant during February
1995, the plant has the capacity to produce approximately 1.25 billion gross
pounds (521 million net) of ethylene and 92 million gross pounds (38 million
net) of polymer-grade propylene annually.
In 1995 and 1994, the Company's net ethylene sales were 462 million pounds
and 436 million pounds, respectively, and its net propylene sales were 35
million pounds and 32 million pounds, respectively. The Company sells its share
of the ethylene produced by the plant to several major customers for the
manufacture
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of plastics used in various consumer products. The sales price of ethylene
averaged $0.25 per pound in 1995 and $0.20 per pound in 1994. Sales of
propylene, used in the manufacture of various products such as building
materials, clothing and tires, averaged $0.19 per pound and $0.14 per pound in
1995 and 1994, respectively.
During 1995, the average margin per pound of the Company's ethylene was
$0.13 per pound as compared to $0.06 per pound for 1994. Ethylene margins for
the fourth quarter of 1995 declined to an average of approximately $0.06 per
pound as compared to $0.12 per pound in the fourth quarter of 1994. The
Company's ethylene margin is primarily affected by the price received for the
ethylene and the cost of feedstock (natural gas liquids). Higher ethylene
prices, resulting from tight supplies of ethylene and increased demand, and
lower feedstock costs caused significantly higher margins during the second half
of 1994 and the first half of 1995 than margins currently experienced. See Item
7 -- Management's Discussion and Analysis of Financial Condition and Results of
Operations.
Capital expenditures for the petrochemical business were $6 million (net to
the Company) during 1995. The Company plans to spend $10 million (net to the
Company) in capital expenditures for the petrochemical business during 1996,
which include costs for projects to enhance production and efficiency.
Storage and Transportation. In addition to the Geismar plant, the Company
owns and operates a 192-mile ethane feedstock pipeline system, which transports
feedstock to its ethylene plant from several major suppliers, including the
Company's natural gas liquids fractionation plant and supporting 133 mile
pipeline system in Rayne, Louisiana. The Company also operates underground
storage terminals and a 78-mile ethylene pipeline system, portions of which are
jointly owned, to serve the Geismar facility and several other petrochemical
plants in the Baton Rouge area.
OTHER MATTERS
Environmental. Various international, federal, state and local laws and
regulations covering the discharge of materials into the environment, or
otherwise relating to the protection of the environment, affect the Company's
operations and costs. In particular, the Company's petrochemical manufacturing,
gas liquids fractionation plant and other facilities for transporting,
fractionating, treating, storing or otherwise handling hydrocarbons and
hydrocarbon products and wastes therefrom are subject to stringent environmental
regulations relating to, among other things, solid and hazardous waste
management and disposal, air emissions, waste water treatment and other matters
that may affect the environment. Environmental regulations have had an
increasing impact upon the Company's operations. The Company is committed to
managing its operations in a safe and environmentally responsible manner and
believes that its operations and facilities are in general compliance with
applicable environmental regulations. Environmental expenditures for 1995 were
not material, nor are they expected to be material during 1996.
The Company is unable to estimate the impact that current international,
federal and state standards and proposed initiatives or other future
developments in environmental regulations may have on future earnings or
operations, but it believes that required expenditures would not significantly
impact its competitive position with respect to other oil and gas and
petrochemical companies and would not be expected to have a material adverse
effect on the Company's financial position. Nevertheless, the risks of
substantial costs and liabilities are inherent in operations such as the
Company's. There can be no assurance that significant costs and liabilities will
not be incurred in the future.
The Company has, in the past, owned, leased or operated numerous properties
in the U.S. that have been used for the production of oil and gas for many
years. Although the Company believes that its operating and disposal practices
were standard in the industry at the time and were generally in compliance with
then-existing rules and regulations, certain wastes may have been disposed of or
released or contamination has occurred on or under the properties owned, leased
or operated by the Company. State and federal laws applicable to oil and gas
wastes and properties have gradually become more strict. In addition, the
Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"),
also known as the "superfund" law, and comparable state laws impose liability,
without regard to fault or the legality of the original conduct, on certain
classes of persons that have contributed to the release of a "hazardous
substance"
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into the environment. Under these laws, the Company could be required in the
future, including with respect to past and future properties, to remove or
remediate previously disposed of wastes or property contamination (including
groundwater contamination at onshore locations), to perform remedial plugging
operations to prevent future contamination or to clean up disposal sites where
"hazardous substances" from its operations have been taken.
The Company's foreign operations are similarly subject to foreign laws
covering environmental and worker safety matters. Although these laws have
generally been less comprehensive than their U.S. counterparts, countries in
which the Company does business are increasing their environmental regulatory
and compliance standards. The Company's operations in the U.K. are subject to
the Prevention of Oil Pollution Act, the Environmental Protection Act and
related statutes and orders, as well as certain European Union agreements. The
foreign laws, however, have not had, and are not presently expected to have, a
material adverse effect on the Company.
While the outcome of environmental contingencies, lawsuits or other
proceedings against the Company cannot be predicted with certainty, management
expects that such liabilities, to the extent not provided for through insurance
or otherwise, will not have a material adverse effect on the financial position
of the Company.
Insurance. The oil and gas and petrochemical businesses can be hazardous,
involving unforeseen circumstances such as blowouts, explosions or environmental
damage. To address the hazards inherent in the oil and gas and petrochemical
businesses, the Company maintains a comprehensive insurance program covering its
worldwide interests. This insurance coverage includes physical damage coverage,
third party and comprehensive general liability insurance, as well as redrill,
well control and environmental and pollution coverage, although coverage for
environmental and pollution-related losses is subject to significant
limitations. In addition, the Company maintains business interruption insurance
on its major international oil and gas producing interests and on its
petrochemical business. The scope, amount and cost of this insurance vary
depending upon various market factors.
Competition. The Company actively competes for exploration leases,
licenses, concessions and acquisitions, frequently against companies with
substantially greater financial and other resources, such as technical
capabilities and human resources. In addition, some of the Company's competitors
have greater experience, especially in certain international areas where the
Company is currently seeking to acquire interests.
Regulation of Oil and Gas Production and Marketing. Petroleum production is
subject to various types of regulation throughout the world. Legislation
affecting the oil and gas industry is under regular review for amendment or
expansion, frequently increasing the regulatory burden. Statutes and regulations
require permits for drilling operations, drilling bonds and reports concerning
operations. Also, numerous departments and agencies are authorized by statute to
issue and have issued rules and regulations binding on the oil and gas industry
and its individual members. These rules and regulations pose difficult and
costly compliance and reporting requirements, some of which carry substantial
penalties for the failure to comply. Most of the foreign countries in which the
Company operates have statutes and regulations governing conservation matters,
including the unitization or pooling of oil and gas properties and rates of
production from oil and gas wells. The regulatory burden on the oil and gas
industry increases its costs of doing business and, consequently, affects its
profitability.
Employees. As of February 29, 1996, the Company had approximately 1,100
employees. The Company believes that its relations with its employees are good.
General. In July 1985, two limited partnerships (the "KKR Partnerships"),
which are affiliated with Kohlberg Kravis Roberts & Co. ("KKR"), purchased
approximately 50% of the then outstanding common stock of the Company from
AlliedSignal Inc. ("Allied"). In September 1987, the Company sold 18,000,000
shares of its common stock in concurrent public offerings in the United States
and outside the United States. In November 1992, Allied sold, in a secondary
public offering, its 33,333,334 shares of common stock, which represented
approximately 39% of the Company's issued and outstanding shares of common
stock. In May 1995, the KKR Partnerships sold, in a secondary public offering,
11,500,000 shares of their 33,333,334
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shares of common stock, which represented approximately 13% of the Company's
issued and outstanding shares of common stock. The Company did not receive any
proceeds from the secondary public offerings. The KKR Partnerships currently own
approximately 25% of the Company's issued and outstanding shares of common
stock. See Item 7 -- Management's Discussion and Analysis of Financial Condition
and Results of Operations and Note 1 of Notes to Consolidated Financial
Statements.
In 1991, the Company consummated three separate transactions in which it
sold its U.S. onshore and offshore exploration and production businesses and its
gas processing business for a total cash consideration of approximately $861
million. The buyers in each of the transactions assumed substantially all of the
liabilities related to the respective businesses or assets that they acquired.
During 1992, the Company successfully completed a financial restructuring
through a series of financial transactions that significantly streamlined its
capital structure. The Company redeemed its outstanding $410 million of
subordinated notes, redeemed for $200 million plus accrued dividends its
outstanding Series B and Series C Preferred Stock, redeemed for $300 million its
outstanding warrants to purchase the Company's common stock and repaid at
maturity its $100 million senior subordinated notes. In 1992, the Company also
issued $100 million in principal amount of senior notes. Since 1992, the Company
has continued to restructure its financial position, including the redemption
for $75 million plus accrued dividends of its outstanding Preferred Auction Rate
Stock. In 1995, the Company restructured its credit facilities, and publicly
issued $300 million principal amount of notes at varying maturities and interest
rates. A subsidiary of the Company also entered into a 150 million pounds
sterling secured financing in 1995 to fund the Company's share of the cost of
development of the Britannia field. In addition, in 1995 the Company authorized
a new class of 15 million shares of preferred stock that may be issued from time
to time. For more information regarding these transactions, see Item
7 -- Management's Discussion and Analysis of Financial Condition and Results of
Operations and Note 7 of Notes to Consolidated Financial Statements.
ITEM 2. PROPERTIES.
For a description of the Company's properties, see Item 1 of Part I of this
Annual Report on Form 10-K.
ITEM 3. LEGAL PROCEEDINGS.
The Company and its subsidiaries and related entities are named defendants
in numerous lawsuits and named parties in numerous governmental proceedings
arising in the ordinary course of business.
While the outcome of the contingencies, lawsuits or other proceedings
against the Company cannot be predicted with certainty, management expects that
such liability, to the extent not provided for through insurance or otherwise,
will not have a material adverse effect on the financial statements of the
Company.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
None.
23
<PAGE> 26
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
Since September 24, 1987, the Company's common stock, $.05 par value (the
"Common Stock"), has been traded on the New York Stock Exchange and the Pacific
Stock Exchange under the symbol "UTH." As of February 29, 1996, there were
approximately 87,597,350 shares of Common Stock outstanding held by
approximately 304 stockholders of record. Beginning with the second quarter of
1988, the Company has paid regular quarterly dividends on the Common Stock of
$.05 per share each quarter. See Item 7 -- Management's Discussion and Analysis
of Financial Condition and Results of Operations.
The following table shows the high and low sales prices of the Common Stock
from the New York Stock Exchange Composite for 1995 and 1994:
<TABLE>
<CAPTION>
1995 1994
------------------------------------------------------------------- -------------------------------
QUARTER ENDED QUARTER ENDED
------------------------------------------------------------------- -------------------------------
MARCH 31 JUNE 30 SEPT. 30 DEC. 31 MARCH 31 JUNE 30
------------- ------------- ------------- ------------- ------------- -------------
<S> <C> <C> <C> <C> <C> <C>
High.......... 23 1/8 23 7/8 21 1/2 19 7/8 22 20 1/8
Low........... 18 1/4 21 18 17 1/8 16 5/8 16 1/4
<CAPTION>
1994
-------------------------------
QUARTER ENDED
-------------------------------
SEPT. 30 DEC. 31
------------- -------------
<S> <C> <C>
High.......... 20 3/8 21 7/8
Low........... 17 18 1/8
</TABLE>
Source of Prices: New York Stock Exchange Composite Transactions Tape
The last reported sale price of the Common Stock on the New York Stock
Exchange on February 29, 1996, was $19 3/4.
24
<PAGE> 27
ITEM 6. SELECTED FINANCIAL DATA.
The financial data as of and for the years ended December 31, 1991 through
1995 were derived from the audited consolidated financial statements of the
Company and should be read in connection with the consolidated financial
statements and related notes included elsewhere herein. See also Item
1 -- General.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------------------------------------------
1995 1994 1993 1992 1991
----------- ---------- ---------- --------- -----------
(DOLLARS IN THOUSANDS EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C>
OPERATING DATA:
Revenues........................................... $ 876,029 $ 769,595 $ 696,663 $ 714,012 $ 1,080,261
Costs and other deductions:
Product costs and operating expenses............. 299,133 299,586 301,276 316,985 552,884
Exploration expenses............................. 77,185 53,532 93,640 67,129 70,661
Depreciation, depletion and amortization......... 191,503 168,570 242,704 77,143 125,479
Selling, general and administrative expenses..... 26,098 24,525 23,780 27,008 43,777
Interest expense................................. 28,783 11,399 6,369 3,958 47,376
Preferred dividends of a subsidiary.............. 1,911 2,398 3,709
Other charges (credits), net..................... 6,185 (211,597)
----------- ---------- ---------- ---------- -----------
Income before income taxes, extraordinary items and
cumulative effect of changes in accounting
principles....................................... 253,327 211,983 26,983 213,206 447,972
Income taxes (benefit)............................. 150,977 145,245 (3,686) 103,808 168,029
----------- ---------- ---------- ---------- -----------
Income before extraordinary items and cumulative
effect of changes in accounting principles....... 102,350 66,738 30,669 109,398 279,943
Extraordinary items(a)............................. (19,682) 52,907
Cumulative effect of changes in accounting
principles....................................... (3,743) (76,080)(b)
----------- ---------- ---------- ---------- -----------
Net income......................................... $ 102,350 $ 66,738 $ 26,926 $ 13,636 $ 332,850
=========== ========== ========== ========== ===========
Net income (loss) applicable to common
stockholders..................................... $ 102,350 $ 66,738 $ 26,926 $ (16,586) $ 292,100
=========== ========== ========== ========== ===========
Earnings (loss) per share of common stock:
Income before extraordinary items and cumulative
effect of changes in accounting principles..... $ 1.17 $ .76 $ .35 $ .86 $ 2.59
Extraordinary items.............................. (.23) .52
Cumulative effect of changes in accounting
principles..................................... (.04) (.89)
----------- ----------- ----------- ---------- -----------
Net income (loss)................................ $ 1.17 $ .76 $ .31 $ (.26) $ 3.11
=========== =========== =========== ========== ===========
Weighted average shares outstanding................ 87,686,777 87,642,451 87,218,027 85,823,320 85,189,916
Dividends per share of common stock................ $ .20 $ .20 $ .20 $ .20 $ .20
=========== =========== =========== ========== ===========
BALANCE SHEET DATA (AT END OF PERIOD):
Net working capital................................ $ (36,269) $ (44,439) $ (52,035) $ 33,630 $ 576,397
Property, plant and equipment -- net............... 1,551,198 1,286,278 1,088,884 1,198,949 1,157,414
Total assets....................................... 1,836,818 1,544,634 1,338,741 1,580,645 2,246,567
Long-term debt..................................... 712,132 536,117 447,374 474,189 421,924
Redeemable preferred stock......................... 75,000 275,000
Common stock and other stockholders' equity........ 423,790 349,499 281,246 269,197 674,428
</TABLE>
- ---------------
(a) In the year ended December 31, 1991, the Company recognized an
extraordinary tax benefit of $53 million from utilization of net operating
loss carryforwards as a result of the sale of its domestic exploration,
production and gas processing businesses for $861 million in cash. In the
first quarter of 1992, the Company recognized an extraordinary loss of $20
million as a result of the early redemption of its Senior Subordinated
Reset Notes and 13% Subordinated Notes.
(b) In 1992, the Company adopted, effective January 1, 1992, two new accounting
standards for income taxes and postretirement benefits, respectively.
25
<PAGE> 28
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.
RESULTS OF OPERATIONS
1995 Compared with 1994. Net income for the year ended December 31, 1995
was $102 million, or $1.17 per share as compared to net income of $67 million,
or $.76 per share reported for the year ended December 31, 1994. The 1995
earnings were favorably impacted by higher U.S. ethylene margins and sales
volumes, higher volumes and prices in the U.K. and Pakistan and higher
Indonesian LNG prices, partially offset by higher exploration expenses, higher
interest expense and lower LNG volumes in Indonesia.
Sales and operating revenues for 1995 were $852 million up from $748
million in 1994. International revenues totaled $651 million as compared to $578
million in 1994. In the U.K., sales and operating revenues increased by $63
million due to higher prices and increased sales volumes which were primarily a
result of the July 1995 acquisition of an interest in the Alba field. In
Indonesia, sales were $2 million below 1994 as a result of lower LNG volumes,
partially offset by higher prices. Lower LNG volumes were attributable to a
lower average participation interest in cargoes delivered during 1995 and the
timing of deliveries. In Pakistan, sales were $12 million above 1994 due to
higher volumes and prices.
Petrochemical revenues totaled $200 million in 1995 as compared to $169
million in the prior year, while operating profit was $62 million as compared to
$24 million in 1994. The increase in operating profit was primarily due to
higher ethylene sales prices and lower feedstock cost, which resulted in an
increase in ethylene margins to 13 cents per pound in 1995 vs. 6 cents per pound
in 1994, as well as higher volumes.
Average prices received and volumes sold by the Company's major operations
during 1995 and 1994, respectively, were as follows:
<TABLE>
<CAPTION>
VOLUMES
PRICES (000S PER DAY)
--------------------- -------------------
1995 1994 1995 1994
------ ------ ----- -----
<S> <C> <C> <C> <C>
Crude oil (barrels):
U.K......................................... $16.14 $14.99 40 34
Pakistan.................................... 14.24 13.43 6 5
Indonesia................................... 17.14 15.78 6 6
Indonesian LNG (Mcf).......................... 3.03 2.85 205 222
Pakistan natural gas (Mcf).................... 1.32 1.07 45 43
U.K. natural gas (Mcf)........................ 2.78 2.57 34 24
U.S. ethylene (pounds)........................ .25 .20 1,267 1,195
</TABLE>
Exploration expenses increased by $24 million primarily due to drilling
expenditures in Argentina, Ireland, Tunisia, Vietnam and Eastern Indonesia.
Interest expense increased by $17 million during the year due to higher levels
of debt associated with the Alba acquisition and to higher interest rates. The
effective tax rate decreased from the prior year due primarily to the increase
in U.S. petrochemical income, which is taxed at lower rates, partially offset by
higher new venture exploration expenses, most of which generate no tax benefits.
1994 Compared with 1993. Net income for the year ended December 31, 1994
was $67 million, or $.76 per share, as compared to net income of $27 million, or
$.31 per share reported for the year ended December 31, 1993. Included in 1993
results are certain non-recurring items; excluding these items, net income for
the year ended December 31, 1993, was $54 million, or $.61 per share. The 1994
earnings were favorably impacted by higher volumes in the U.K. North Sea and
Indonesia, higher U.S. ethylene margins and lower operating expenses, partially
offset by lower oil and LNG prices and higher depreciation, depletion and
amortization expense related to the increased production.
Sales and operating revenues for 1994 were $748 million, up approximately
10% from $682 million in 1993. International revenues totaled $578 million as
compared to $537 million in 1993. In the U.K., sales and operating revenues
increased $52 million as lower crude prices were more than offset by increased
production from the Piper block. In Indonesia, sales were $1 million below 1993
as a result of lower crude oil and LNG prices, which were partially offset by
higher LNG volumes. In Pakistan, sales were $10 million below 1993
26
<PAGE> 29
primarily due to lower prices for crude oil and natural gas. The average sales
price for U.K. crude oil decreased from $15.10 to $14.99 per barrel. The average
sales price received for Indonesian LNG decreased from $3.17 per Mcf to $2.85
per Mcf. The average sales price for Pakistan natural gas decreased from $1.26
per Mcf to $1.07 per Mcf.
Production costs per barrel of oil equivalent ("boe") for the Company's oil
and gas activities averaged $3.98 in 1994, down from $4.73 per boe in 1993
primarily as a result of increased volumes in the U.K., lower LNG plant costs in
Indonesia and the benefits of a Company-wide cost containment program.
The operating profit for the Company's petrochemical operations was $16
million above the prior year. The increase primarily resulted from improved
ethylene margins reflecting higher sales prices for ethylene and lower costs.
The prior year's results included four non-recurring items which in the
aggregate reduced 1993 earnings by $27 million. These items included
depreciation expense of $103 million ($48 million after tax) representing a
write-down of the Company's investment in the Piper field, a $25 million charge
to exploration expense due to the write-off of the Company's investment in the
Kuvlum prospect in Alaska and a $4 million charge for the cumulative effect of
adopting a new accounting standard for postemployment benefits. Partially
offsetting these items was a $50 million tax benefit associated with changes to
U.K. tax laws.
Exploration expenses decreased by $40 million due to the prior year
write-off of Kuvlum, lower worldwide operating expenditures and reduced
expenditures in the U.K. and Indonesia. Depreciation, depletion and amortization
decreased by $74 million due to the prior period's write-down of the Piper
field, which was partially offset by increased production. Interest expense
increased $5 million due to lower capitalized interest related to the Piper
redevelopment project, which was substantially completed in 1993. The effective
tax rate was essentially level with the prior period, adjusted for the
non-recurring items mentioned previously.
FINANCIAL CONDITION AND LIQUIDITY
General. The Company's capital expenditures for 1996 reflect a focus on
core holdings and a diversified exploration program. The Company's capital
expenditures for 1996 are estimated to be about $220 million, excluding
capitalized interest. Approximately $152 million of the 1996 capital budget is
allocated for oil and gas development projects in the U.K. North Sea, Indonesia
and Pakistan, including $60 million for the continued development of the
Britannia field and $16 million for development activities at the producing Alba
oil field. The Company has budgeted approximately $21 million for exploration
projects in the U.K. North Sea, Pakistan and Indonesia and has allocated $18
million for its activities in Alaska, including the Western Colville area on the
North Slope, and $16 million in new venture exploration activities primarily in
Tunisia, Italy, Ireland and Argentina. The Company has also budgeted
approximately $10 million for its petrochemical interests in the United States.
During 1996, the Company also intends to evaluate acquisition opportunities
worldwide of both developed and undeveloped oil and gas reserves, the costs of
which are not included in the capital expenditure budget. Based on existing
economic and market conditions, the Company believes operating cash flow will be
sufficient to fund its 1996 development and exploration activities and that its
available equity and financial credit strength give the Company financial
resources to make acquisitions.
Cash flow from operations. Net cash provided by operating activities was
$234 million in 1995, an increase of $19 million from the prior year. The
increase was primarily the result of increased U.K. oil volumes, improved
ethylene margins and increased oil and gas prices, partially offset by lower LNG
volumes.
Ethylene margins averaged approximately 13 cents per pound during 1995, as
compared to 6 cents per pound for 1994. However, ethylene margins averaged
approximately 6 cents per pound during the fourth quarter of 1995 and 4 cents
per pound for the month of December 1995. The ethylene business is cyclical and
the Company cannot predict the duration of any trends in the business. Prices
for ethylene are affected by worldwide and U.S. demand for petrochemicals,
inventory levels, feedstock costs and availability, plant utilization rates,
plant operations and costs and competitive capacity expansion. The Company
estimates that a margin change of an average one cent per pound for an entire
year at full capacity production can effect
27
<PAGE> 30
operating profit and net income on an annualized basis for the petrochemical
business of the Company by approximately $5 million.
Capital resources. Capital expenditures for 1995 (excluding the $270
million Alba acquisition), were $172 million, an increase from the prior year's
expenditures of $131 million (excluding the $159 million Britannia acquisition).
This increase was a result of the expanded exploration program and development
activity for the Britannia field. In 1995, 1994 and 1993, total Company capital
costs incurred, including capitalized interest and the Alba and Britannia
acquisitions, totaled $465 million, $309 million and $218 million, respectively.
On July 18, 1995, the Company, through its subsidiary, Union Texas
Petroleum Limited ("UTPL"), acquired from Oryx UK Energy Company ("Oryx") a
15.5% working interest in Block 16/26 in the central United Kingdom North Sea,
which includes the Alba field. UTPL paid Oryx $270 million for the interest. The
effective date of the transaction was July 1, 1995. The Company funded the
acquisition under its bank credit facilities and its uncommitted and unsecured
lines of credit. As of December 31, 1995, the Company had recorded 43 million
barrels of oil as proved reserves, of which 23 million barrels are classified as
proved undeveloped. The Alba field commenced production in January 1994 and is
operated by Chevron U.K. Limited.
Financing activities. The Company had three unsecured credit facilities
(the "Credit Facilities") at December 31, 1995. One of the Credit Facilities is
a $100 million unsecured credit agreement with a syndicate of banks, that
provides for conversion of amounts outstanding on April 15, 1996 to a one-year
term loan maturing April 15, 1997. Another Credit Facility is a $450 million
unsecured credit agreement with a syndicate of banks that provides for a
quarterly reduction of $35 million beginning July 31, 1998, with a final
maturity of April 30, 1999. The Company is pursuing the extension of the
maturity of the $450 million Credit Facility and the replacement of the $100
million Credit Facility. The $450 million revolver allows the Company to obtain
up to $300 million of availability thereunder in U.S. dollar loans that bear
interest at a rate determined in a competitive bid process. Loans under the $450
million revolver may be made in both pounds sterling and U.S. dollars at the
option of the Company. In June 1995, the Company entered into an additional $100
million unsecured credit agreement with certain banks providing for conversion
of amounts outstanding on June 15, 1996 to a one-year term loan maturing June
15, 1997. This undrawn facility was terminated January 31, 1996. Loans under the
Credit Facilities bear interest at floating market rates based on, at the
Company's option, the agent bank's base rate or LIBOR, plus applicable margins,
subject to increase in certain events. The Credit Facilities contain restrictive
covenants, including maintenance of certain coverage ratios related to the
incurrence of additional indebtedness and limitations on asset sales and mergers
or consolidations. The covenants also require maintenance of stockholders'
equity, as adjusted, at $350 million. Under the terms of the Credit Facilities,
the Company may pay dividends and make stock repurchases provided that such
level of minimum stockholders' equity is maintained and the Company complies
with certain other covenants in the Credit Facilities. At December 31, 1995, the
Company's adjusted stockholders' equity was approximately $500 million. At
December 31, 1995, $132 million was outstanding under the $450 million revolver
bearing interest at a weighted average rate of 6.17% per annum.
Due to the Company's ability to obtain favorable interest rates on
short-term borrowings, uncommitted and unsecured lines of credit were
established with several banks in both U.S. dollars and pounds sterling. These
money market borrowings, which have a short-term maturity, have been classified
as long-term debt based on the Company's intent to refinance these borrowings
for a period exceeding one year and the ability to refinance them on a long-term
basis through its Credit Facilities. At December 31, 1995 and 1994, $148 million
and $106 million, respectively, were outstanding under these money market lines
which bore interest at weighted average rates of 6.5% and 6.46% per annum,
respectively. At December 31, 1995, the Company has adjusted the 1994 balance
sheet by reclassifying outstanding money market borrowings of $106 million from
current liabilities to long-term debt. Management believes that this
presentation is more meaningful for comparative analysis and appropriately
reflects management's intent at December 31, 1994. At February 29, 1996, $115
million and $119 million were outstanding under the Credit Facilities and the
uncommitted lines of credit, respectively. As of such date, the Company had
approximately $314 million of such available financing.
28
<PAGE> 31
In May 1995, the Company's indirect subsidiary, Union Texas Britannia
Limited ("UTBL"), which is a wholly owned subsidiary of UTPL, entered into a 150
million pounds sterling secured financing from a syndicate of banks. The
financing is used to fund the Company's share of the cost of developing the
Britannia field to production (including interest and other financing costs
incurred prior to completion and potential cost overruns), and any remaining
availability after completion may, subject to certain coverage ratios being met,
be used for UTBL's general corporate purposes. Except for certain support by
UTPL related to any potential cost overruns in excess of the facility amount
(limited to 30 million pounds sterling), insurance, tax benefits and
administrative services, the lenders' recourse will be limited to the Britannia
field project assets and is nonrecourse to the Company. The financing has a
final maturity in September 2005. At December 31, 1995, 19 million pounds
sterling ($29 million) was outstanding under UTBL's financing.
In May 1995, pursuant to the secondary public offering registered by the
Company under the Securities Act of 1933, as amended, 11.5 million shares of the
33.3 million shares of the Company's common stock owned by partnerships
affiliated with Kohlberg Kravis Roberts & Co. ("KKR") were sold in the open
market. The Company did not receive any proceeds from the offering. KKR
currently owns 21.8 million shares (approximately 25%) of the Company's issued
and outstanding common stock.
In March 1995, the Company publicly issued $125 million principal amount of
8 3/8% Senior Notes due 2005 (the "8 3/8% Senior Notes") at an initial public
offering price of 99.431%. In April 1995, the Company publicly issued $75
million principal amount of 8 1/2% Senior Notes due 2007 (the "8 1/2% Senior
Notes") at an initial public offering price of 99.658%. The net proceeds from
the sale of the 8 3/8% Senior Notes and the 8 1/2% Senior Notes were
approximately $123.5 million and $74.2 million, respectively (after deducting
underwriting discount, commissions and offering expenses). The Company used such
proceeds to reduce debt under its existing credit facility and its uncommitted
and unsecured lines of credit. The Company's $100 million principal amount of
8.25% Senior Notes due 1999 ("the 8.25% Senior Notes") together with the 8 1/2%
Senior Notes and the 8 3/8% Senior Notes are referred to herein as the "Senior
Notes." The Senior Notes represent general unsecured obligations of the Company
and rank pari passu in right of payment with the Company's obligations under its
Credit Facilities, and senior in right of payment to any future subordinate
indebtedness of the Company. Each of the Senior Notes contain similar
restrictive covenants. The Senior Notes are redeemable at any time, at the
option of the Company, in whole or in part, at a price equal to 100% of their
principal amount plus accrued interest plus a make whole premium relating to the
then-prevailing Treasury Yield and the remaining life of the Senior Notes.
During 1995, the Company obtained the release of the guarantees by certain
subsidiaries of the Company of the Company's Credit Facilities and the Senior
Notes.
In 1995, the Company issued $100 million aggregate principal amount of
medium term notes ("MTN") with terms of seven and twelve years and interest
rates varying from 6.51% to 6.81%. The net proceeds from the sale of the MTN
were approximately $99.4 million and were used to reduce debt under the
Company's credit facility and its uncommitted and unsecured lines of credit.
These MTN represent general unsecured obligations of the Company and rank pari
passu in right of payment with the Company's obligations under its Credit
Facilities and Senior Notes and senior in right of payment to any future
subordinated indebtedness of the Company. Each of the MTN contain similar
restrictive covenants as the Senior Notes. The MTN are redeemable at any time,
at the option of the Company, in whole or in part, at a price equal to 100% of
the principal amount plus accrued interest plus a make-whole premium relating to
the then-prevailing Treasury Yield and the remaining life of the MTN.
At the 1995 Annual Meeting of Stockholders held May 10, 1995, the Company's
stockholders approved the authorization of a new class of 15 million shares of
preferred stock. The new unissued preferred stock provides the Company
additional financing flexibility to issue from time to time based on current
market conditions.
On April 27, 1994, the Company's Board of Directors authorized the
repurchase of up to 2,000,000 shares of the Company's common stock and pursuant
thereto, the Company had repurchased 554,536 shares as of December 31, 1995. The
repurchased stock will be used for general corporate purposes, including
fulfilling
29
<PAGE> 32
employee benefit program obligations. At December 31, 1995, 247,145 shares of
common stock were held, at cost, as treasury shares.
As of December 31, 1995, the Company's scheduled maturities of long-term
debt outstanding for the five-year period of 1996 through 2000 are approximately
$2 million, $2 million, $0 million, $396 million and $14 million, respectively.
The Company believes that it will have sufficient sources of funds to satisfy
these scheduled maturities. The Company may enter into interest rate swap
contracts from time to time. However, the Company did not enter into any
interest rate swap contracts during 1995.
Financial Condition. In each of the four quarters ended December 31, 1995,
the Company declared and paid a dividend of approximately $4.3 million on its
common stock. On January 18, 1996, the Company announced a dividend on its
common stock of $.05 per share to stockholders of record as of January 31, 1996,
which was paid on February 15, 1996.
In October 1995, the Financial Accounting Standards Board released
Statement of Financial Accounting Standards No. 123, "Accounting for Stock-Based
Compensation," which establishes financial and reporting standards for stock
based employee compensation plans that will be effective for the Company's 1996
financial statements. The statement encourages, but does not require, companies
to adopt a fair value based method of accounting for such plans in place of
current accounting standards. Companies electing to continue to use their
existing accounting methods will be required to make pro forma disclosures of
net income assuming a fair value based method of accounting has been applied.
The Company is evaluating the Statement as to whether to adopt the fair value
based method of accounting or continue using its current accounting methods with
additional disclosures.
The Company may enter into hedging contracts from time to time in order to
minimize the impact of adverse price fluctuations; however, the Company did not
enter into any of these contracts during 1995. In the first quarter of 1996, the
Company entered into financial hedging futures contracts to offset a portion of
its North Sea crude. The Company will continue to consider other opportunities
in its risk management activities, such as swaps or fixed price contracts to
mitigate the adverse movement in oil and gas prices. Gains or losses on these
hedging activities are recognized in sales revenues when the underlying exposed
hedged production is sold. As of February 29, 1996, the Company had open
contracts for 600,000 barrels of oil at an average Brent price of $16.54 per
Bbl.
The functional currency for translating the accounts of foreign
subsidiaries is the U.S. dollar, except for subsidiaries in the United Kingdom
where the functional currency is pounds sterling. The Company's revenues are
predominantly based upon the world market price for crude oil, which is
denominated in U.S. dollars. Certain operating costs, taxes, capital costs and
intercompany transactions represent commitments settled in foreign currencies.
Exchange rate fluctuations on transactions in currencies other than the
functional currency are recognized as gains and losses in current period income.
The Company periodically enters into foreign exchange contracts as a hedge
against fluctuations in foreign currency rates. These contracts are generally of
a short-term nature. At December 31, 1995, the Company had open contracts with a
net value of 21 million pounds sterling. However, there are foreign exchange
risks inherent in operations such as the Company's, and the Company cannot
predict with any certainty the results of currency exchange rate fluctuations.
The Company also cannot predict with any degree of certainty the prices it
will receive in 1996 and future years for its crude oil, LNG, natural gas and
ethylene. In addition, uncertainty in the Middle East, policies of oil exporting
countries and worldwide demand for products affect the Company's sales. The
marketing of products and the prices the Company receives for such products are
sensitive to many factors beyond the control of the Company. The Company's
financial condition, operating results and liquidity may be materially affected
by any significant fluctuations in its sales prices. The Company's ability to
service its long-term obligations and to internally generate funds for capital
expenditures will be similarly affected. See Notes 13 and 17 of Notes to
Consolidated Financial Statements for information regarding the Company's
estimated proved reserves and sales.
Likewise, the Company's business is affected by its costs and success in
finding, developing or acquiring new reserves to replace its reserves depleted
by production. Certain of the Company's producing properties are
30
<PAGE> 33
at normal decline in production rates. In general, the Company's volume of
production from oil and gas properties declines with the passage of time. In
addition, the Company's participation share of gas volumes supplied to support
Indonesian LNG sales contract extensions or additions are and will be
significantly less than their participation share under the original long-term
sales contracts. The Company's long-term strategy is to increase its production
with successful exploration and development activities and selective reserve
acquisitions. There can be no assurances that the Company will achieve such
objectives. Except to the extent the Company conducts successful exploration,
exploitation or development activities, acquires additional properties
containing proved reserves or both, the proved reserves of the Company, and the
revenues generated from production thereof (assuming no price increases), will
decline as reserves are produced. Drilling activities are expensive and subject
to numerous risks, including the risk that no commercially viable oil or gas
production will be obtained. Also, the Company must compete with a substantial
number of other energy companies, any of which may have significantly greater
financial and other resources than the Company. Increases or decreases in prices
of oil and gas and in cost levels, along with the timing of development
projects, will also affect revenues generated by the Company and the present
value of estimated future net cash flows from its properties. Revenues generated
from future activities of the Company are highly dependent upon the level of
success in finding, developing or acquiring additional reserves. See Notes 1 and
17 of Notes to Consolidated Financial Statements.
The Company's overseas operations are subject to certain risks, including
expropriation of assets, governmental reinterpretation of applicable law and
contract terms, increases in taxes and government royalties, renegotiation of
contracts with foreign governments or customers, foreign government approvals of
lease, permit or similar applications and of exploration and production plans,
political and economic instability, disputes between governments, exclusive
jurisdiction of foreign courts, payment delays, export restrictions, increased
environmental regulations, limits on allowable levels of exploration and
production and currency exchange losses and repatriation restrictions, as well
as changes in laws and policies governing operations of companies with overseas
operations generally. Foreign operations and investments may also be subject to
laws and policies of the United States affecting foreign trade, investment and
taxation that could affect the conduct and profitability of these operations.
All of the Company's activities are subject to the risks normally
associated with exploration for and production of oil and gas as well as the
production of petrochemicals. Also, the Company's activities are subject to
stringent environmental regulations. The Company believes that its operations
and facilities are in general compliance with existing environmental
regulations. Nevertheless, the risks of substantive costs and liabilities are
inherent in operations such as the Company's, and there can be no assurance that
significant costs and liabilities will not be incurred in the future.
The discussion of the Company's business and operations in this report
includes in several instances forward-looking statements, which are based upon
management's good faith assumptions relating to the financial, market, operating
and other relevant environments that will exist and affect the Company's
business and operations in the future. No assurance can be made that the
assumptions upon which management based its forward-looking statements will
prove to be correct, or that the Company's business and operations will not be
affected in any substantial manner by other factors not currently foreseeable by
management or beyond the Company's control. All forward-looking statements
involve risks and uncertainty, including those described in this report, and
such statements shall be deemed in the future to be modified in their entirety
by the Company's public pronouncements, including those contained in all future
reports and other documents filed by the Company with the Securities Exchange
Commission.
31
<PAGE> 34
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
INDEX TO FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Report of Independent Accountants..................................................... 33
Consolidated Balance Sheet, December 31, 1995 and 1994................................ 34
Consolidated Statement of Operations, Years Ended December 31, 1995,
1994 and 1993....................................................................... 35
Consolidated Statement of Cash Flows, Years Ended December 31, 1995,
1994 and 1993....................................................................... 36
Consolidated Statement of Stockholders' Equity, Years Ended December 31, 1995,
1994 and 1993....................................................................... 37
Notes to Consolidated Financial Statements............................................ 38
</TABLE>
32
<PAGE> 35
REPORT OF INDEPENDENT ACCOUNTANTS
To the Stockholders and Directors of
Union Texas Petroleum Holdings, Inc.
In our opinion, the consolidated financial statements listed in the accompanying
index present fairly, in all material respects, the financial position of Union
Texas Petroleum Holdings, Inc. and its subsidiaries at December 31, 1995 and
1994, and the results of their operations and their cash flows for each of the
three years in the period ended December 31, 1995, in conformity with generally
accepted accounting principles. These financial statements are the
responsibility of the Company's management; our responsibility is to express an
opinion on these financial statements based on our audits. We conducted our
audits of these statements in accordance with generally accepted auditing
standards which require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for the opinion expressed above.
As discussed in Note 1 to the consolidated financial statements, the Company
changed its method of accounting for postemployment benefits in 1993.
PRICE WATERHOUSE LLP
Houston, Texas
February 14, 1996
33
<PAGE> 36
UNION TEXAS PETROLEUM HOLDINGS, INC.
CONSOLIDATED BALANCE SHEET
(DOLLARS IN THOUSANDS)
ASSETS
<TABLE>
<CAPTION>
DECEMBER 31,
-------------------------
1995 1994
---------- ----------
<S> <C> <C>
Current assets:
Cash and cash equivalents......................................... $ 11,069 $ 8,389
Accounts and notes receivable, less allowance for doubtful
accounts....................................................... 77,517 54,773
Inventories....................................................... 42,764 43,228
Prepaid expenses and other current assets......................... 27,924 30,675
---------- ----------
Total current assets...................................... 159,274 137,065
Equity investment................................................... 108,476 114,505
Property, plant and equipment, at cost, less accumulated
depreciation, depletion and amortization*......................... 1,551,198 1,286,278
Other assets........................................................ 17,870 6,786
---------- ----------
Total assets.............................................. $1,836,818 $1,544,634
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Current portion of long-term debt................................. $ 2,292 $ 2,292
Accounts payable.................................................. 95,768 89,281
Taxes payable..................................................... 55,779 48,069
Other current liabilities......................................... 41,704 41,862
---------- ----------
Total current liabilities................................. 195,543 181,504
Long-term debt...................................................... 712,132 536,117
Deferred income taxes............................................... 395,289 365,777
Other liabilities................................................... 110,064 111,737
---------- ----------
Total liabilities......................................... 1,413,028 1,195,135
---------- ----------
Stockholders' equity:
Common stock...................................................... 4,391 4,391
Paid in capital................................................... 19,405 19,889
Cumulative foreign exchange translation adjustment and other...... (75,077) (65,476)
Retained earnings................................................. 479,620 394,806
Common stock held in treasury, at cost, 247,145 shares at December
31, 1995 and 221,565 shares at December 31, 1994............... (4,549) (4,111)
---------- ----------
Total stockholders' equity................................ 423,790 349,499
---------- ----------
Total liabilities and stockholders' equity................ $1,836,818 $1,544,634
========== ==========
</TABLE>
- ---------------
* The Company follows the successful efforts method of accounting for oil and
gas activities.
The accompanying notes are an integral part of this financial statement.
34
<PAGE> 37
UNION TEXAS PETROLEUM HOLDINGS, INC.
CONSOLIDATED STATEMENT OF OPERATIONS
(DOLLARS IN THOUSANDS EXCEPT PER SHARE AMOUNTS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------
1995 1994 1993
-------- -------- --------
<S> <C> <C> <C>
REVENUES:
Sales and operating revenues............................. $851,601 $747,883 $681,923
Interest income and other revenues....................... 3,557 1,268 5,858
Net income of equity investee............................ 20,871 20,444 8,882
-------- -------- --------
876,029 769,595 696,663
COSTS AND OTHER DEDUCTIONS:
Product costs and operating expenses..................... 299,133 299,586 301,276
Exploration expenses..................................... 77,185 53,532 93,640
Depreciation, depletion and amortization................. 191,503 168,570 242,704
Selling, general and administrative expenses............. 26,098 24,525 23,780
Interest expense......................................... 28,783 11,399 6,369
Preferred dividends of a subsidiary...................... 1,911
-------- -------- --------
Income before income taxes and cumulative effect of change
in accounting principle.................................. 253,327 211,983 26,983
Provision for (benefit from) income taxes.................. 150,977 145,245 (3,686)
-------- -------- --------
Income before cumulative effect of change in accounting
principle................................................ 102,350 66,738 30,669
Cumulative effect of change in accounting principle........ (3,743)
-------- -------- --------
Net income................................................. $102,350 $ 66,738 $ 26,926
======== ======== ========
EARNINGS PER SHARE OF COMMON STOCK:
Income before cumulative effect of change in accounting
principle............................................. $ 1.17 $ .76 $ .35
Cumulative effect of change in accounting principle...... (.04)
-------- -------- --------
Net income............................................... $ 1.17 $ .76 $ .31
======== ======== ========
DIVIDENDS PER SHARE OF COMMON STOCK........................ $ .20 $ .20 $ .20
======== ======== ========
Weighted average number of shares outstanding (000's)...... 87,687 87,642 87,218
======== ======== ========
</TABLE>
The accompanying notes are an integral part of this financial statement.
35
<PAGE> 38
UNION TEXAS PETROLEUM HOLDINGS, INC.
CONSOLIDATED STATEMENT OF CASH FLOWS
(DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------------
1995 1994 1993
--------- --------- ---------
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income.............................................. $ 102,350 $ 66,738 $ 26,926
Adjustments to reconcile net income to net cash provided
by operating activities:
Cumulative effect of change in accounting
principle.......................................... 3,743
Depreciation, depletion and amortization............. 191,503 168,570 242,704
Deferred income taxes................................ (19,576) (11,962) (107,492)
Net income of equity investee........................ (20,871) (20,444) (8,882)
Other................................................ 3,581 4,027 (7,324)
--------- --------- ---------
Net cash provided by operating activities before
changes in other assets and liabilities......... 256,987 206,929 149,675
(Increase) decrease in accounts and notes
receivable......................................... (22,667) (4,510) 58,438
(Increase) decrease in inventories................... 1,351 (8,187) 4,114
(Increase) decrease in prepaid expenses and other
assets............................................. (6,628) 6,303 (3,639)
(Decrease) increase in accounts payable and other
liabilities........................................ 3,233 19,719 (8,753)
(Decrease) increase in income taxes payable.......... 1,649 (5,618) (9,003)
--------- --------- ---------
Net cash provided by operating activities............ 233,925 214,636 190,832
--------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment.............. (412,039) (299,578) (144,476)
Cash provided by equity investee........................ 26,900 9,050 20,550
Cash required by sale of businesses, net................ (809) (2,488) (43,373)
--------- --------- ---------
Net cash required by investing activities............... (385,948) (293,016) (167,299)
--------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from long-term debt........................ 327,103 80,503 30,000
Payments to settle long-term debt....................... (2,292) (37,292) (117,927)
Net payments under credit facilities.................... (193,503)
Net proceeds from money market lines of credit.......... 43,151 47,130 54,765
Redemption of Preferred Auction Rate Stock.............. (75,000)
Purchase of treasury stock.............................. (4,136) (6,089)
Proceeds from issuance of treasury stock................ 1,916 1,593
Proceeds from issuance of common stock.................. 311 18,849
Dividends paid.......................................... (17,536) (17,530) (17,418)
--------- --------- ---------
Net cash provided (required) by financing activities.... 154,703 68,626 (106,731)
--------- --------- ---------
Net increase (decrease) in cash and cash equivalents.... 2,680 (9,754) (83,198)
Cash and cash equivalents at beginning of year............ 8,389 18,143 101,341
--------- --------- ---------
Cash and cash equivalents at end of year.................. $ 11,069 $ 8,389 $ 18,143
========= ========= =========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid during the period for:
Interest (net of amount capitalized)................. $ 29,765 $ 11,933 $ 8,658
Income taxes......................................... 168,140 154,669 57,791
</TABLE>
The accompanying notes are an integral part of this financial statement.
36
<PAGE> 39
UNION TEXAS PETROLEUM HOLDINGS, INC.
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
(DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------------------
1995 1994 1993
----------- ----------- -----------
<S> <C> <C> <C>
COMMON STOCK (SHARES)
Authorized.......................................... 200,000,000 200,000,000 200,000,000
=========== =========== ===========
Issued:
Beginning of year................................ 87,829,283 87,805,095 86,250,940
Issuance of stock................................ 24,188 1,554,155
----------- ----------- -----------
Ending balance................................... 87,829,283 87,829,283 87,805,095
=========== =========== ===========
COMMON STOCK AT PAR VALUE ($.05 PER SHARE)
Beginning of year................................... $ 4,391 $ 4,390 $ 4,312
Issuance of stock................................... 1 78
----------- ----------- -----------
Ending balance...................................... $ 4,391 $ 4,391 $ 4,390
=========== =========== ===========
PAID IN CAPITAL
Beginning balance................................... $ 19,889 $ 20,436 $ 1,569
Issuance of stock................................... 312 18,770
Reissuance of treasury stock........................ (484) (859) 97
----------- ----------- -----------
Ending balance...................................... $ 19,405 $ 19,889 $ 20,436
=========== =========== ===========
CUMULATIVE FOREIGN EXCHANGE TRANSLATION ADJUSTMENT AND
OTHER
Beginning balance................................... $ (65,476) $ (86,545) $ (69,388)
Translation adjustments............................. (9,406) 20,182 (16,932)
Supplemental pension plan minimum liability......... (195) 887 (225)
----------- ----------- -----------
Ending balance...................................... $ (75,077) $ (65,476) $ (86,545)
=========== =========== ===========
RETAINED EARNINGS
Beginning balance................................... $ 394,806 $ 345,598 $ 336,090
Net income.......................................... 102,350 66,738 26,926
Dividends on common stock........................... (17,536) (17,530) (17,418)
----------- ----------- -----------
Ending balance...................................... $ 479,620 $ 394,806 $ 345,598
=========== =========== ===========
TREASURY STOCK, AT COST
Beginning balance................................... $ (4,111) $ (2,633) $ (3,386)
Purchases........................................... (4,136) (6,089)
Issues.............................................. 3,698 4,611 753
----------- ----------- -----------
Ending balance...................................... $ (4,549) $ (4,111) $ (2,633)
=========== =========== ===========
</TABLE>
The accompanying notes are an integral part of this financial statement.
37
<PAGE> 40
UNION TEXAS PETROLEUM HOLDINGS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(DOLLARS IN THOUSANDS UNLESS OTHERWISE INDICATED)
NOTE 1 -- ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Organization
The Company is engaged in oil and gas exploration and production
principally overseas and petrochemical manufacturing in the United States.
International activities are conducted primarily in Indonesia, the United
Kingdom sector of the North Sea, Pakistan and other strategic areas. Two limited
partnerships (the "KKR Partnerships"), organized and controlled by an affiliate
of Kohlberg Kravis Roberts & Co. ("KKR"), own approximately 25% of the Company's
issued and outstanding common stock.
At the 1995 Annual Meeting of Stockholders held May 10, 1995, the Company's
stockholders approved the authorization of a new class of 15 million shares of
preferred stock. The new unissued preferred stock provides the Company
additional financing flexibility to issue from time to time based on current
market conditions.
Principles of consolidation
The consolidated financial statements include the accounts of Union Texas
Petroleum Holdings, Inc. ("UTPH"), its wholly owned subsidiaries and
proportionate interests in the assets, liabilities and operations of
unincorporated joint ventures (referred to herein individually and collectively
as the "Company"). Investments in which the Company has between a 20% to 50%
ownership interest are accounted for using the equity method. All material
intercompany transactions are eliminated.
Use of estimates
The consolidated financial statements are prepared in conformity with
general accepted accounting principles which requires management to make certain
estimates and assumptions that affect the reported amounts of certain assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements and the related reported amounts of revenues and
expenses during the reporting period. Actual results could differ from those
estimates. Management believes that the estimates are reasonable.
Inventories
Finished product inventories are valued at the lower of cost or market
using the last-in, first-out method ("LIFO"). Materials and supplies inventories
are valued at the lower of average cost or market.
Property, plant and equipment
Oil and gas exploration and production activities are accounted for
employing the successful efforts method. Under this method, costs of successful
exploratory wells, development wells and acreage are capitalized. Costs of
unsuccessful exploratory wells are expensed upon the determination that the well
does not justify commercial development. Other exploration costs including
geological and geophysical costs in exploration areas, delay rentals, production
costs and overhead are charged to expense as incurred.
Major renewals and improvements are capitalized, and the assets replaced
are retired. Maintenance and repairs are expensed as incurred.
Depreciation, depletion and amortization of the capitalized costs of
producing properties, both tangible and intangible, are provided for on the
units-of-production basis. Unit-of-production rates are based on estimated
recoverable oil and gas reserves. Amortization of undeveloped acreage from date
of acquisition is based upon such factors as lease term, estimated evaluation
period and prior experience. The Company reviews its leases and related
amortization rates periodically.
38
<PAGE> 41
UNION TEXAS PETROLEUM HOLDINGS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(DOLLARS IN THOUSANDS UNLESS OTHERWISE INDICATED)
Estimated dismantlement, restoration and abandonment costs net of estimated
salvage value are taken into account in determining amortization. Depreciable
assets other than oil and gas properties are depreciated using the straight-line
method based on estimated asset service lives from 5 to 31 years.
Postemployment benefits
In December 1992, the Financial Accounting Standards Board ("FASB")
released Statement of Financial Accounting Standards No. 112, "Employers'
Accounting for Postemployment Benefits," which concluded that the estimated cost
of benefits provided by an employer to former or inactive employees after
employment but before retirement represents part of the compensation provided to
an employee in exchange for service. The Company currently provides certain
long-term benefits to disabled employees. The Company adopted the Statement
effective January 1, 1993, by recording a cumulative charge to net income of
approximately $4 million representing the estimated future obligation for those
employees currently under the long-term disability program. In prior periods,
the Company's cost of long-term disability was expensed as paid.
Impairment of long-lived assets
In March 1995, the FASB released Statement of Financial Accounting
Standards No. 121, "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to Be Disposed Of," which concluded long-lived assets should
be reviewed for impairment whenever events or changes in circumstances indicate
that the carrying value of an asset may not be recoverable. The Company has
adopted the pronouncement which had no impact on the financial position of the
Company.
Foreign currency
The functional currency for translating the accounts of foreign
subsidiaries is the U.S. dollar, except for subsidiaries in the United Kingdom,
where the functional currency is the local currency. Translation adjustments of
this local currency, which represent unrealized increases and decreases in the
Company's net investment in foreign operations as the result of exchange rate
changes, are included in stockholders' equity as the cumulative foreign exchange
translation adjustment. Transaction gains and losses resulting from the effect
of exchange rate fluctuations on transactions in currencies other than the
functional currency are included in determining net income. Foreign exchange
gains (losses) included in the determination of net income for the years 1995,
1994, and 1993 were ($768), ($178) and $492, respectively.
Foreign exchange contracts
The Company periodically enters into foreign exchange contracts as a hedge
against fluctuations in foreign currency rates. For contracts that hedge
specific transactions, market value gains and losses are deferred and recognized
as a component of cost of the transaction upon consummation. For contracts that
hedge economic exposures, market value gains and losses are recognized in the
period in which they occur.
Other
The fair value of financial instruments included in the Company's assets
and liabilities approximates carrying value. Cash equivalents are comprised of
highly liquid debt instruments purchased at a maturity of three months or less.
39
<PAGE> 42
UNION TEXAS PETROLEUM HOLDINGS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(DOLLARS IN THOUSANDS UNLESS OTHERWISE INDICATED)
NOTE 2 -- PIPER FIELD WRITE-DOWN
In 1993, as a result of the crude oil price environment, it was determined
that estimated future net pretax cash flows from the U.K. Piper field did not
exceed capitalized costs of the field, and accordingly, the Company recorded a
$103 million pretax, non-cash charge to depreciation, depletion and
amortization. After including the reversal of $55 million of related U.K.
deferred income taxes, the net income impact of the charge was $48 million.
NOTE 3 -- ACCOUNTS AND NOTES RECEIVABLE
At December 31, 1995 and 1994, accounts and notes receivable consisted of
the following:
<TABLE>
<CAPTION>
1995 1994
------- -------
<S> <C> <C>
Accounts receivable, trade....................................... $77,593 $54,768
Interest and notes receivable.................................... 8
------- -------
77,593 54,776
Less -- allowance for doubtful accounts.......................... (76) (3)
------- -------
$77,517 $54,773
======= =======
</TABLE>
Most of the Company's worldwide business activity is with major marketing
companies, industrial users and joint venture partners. Those receivables
considered a significant credit risk are backed by letters of credit. Typically,
credit terms are of a short-term nature.
NOTE 4 -- INVENTORIES
At December 31, 1995 and 1994, inventories consisted of the following:
<TABLE>
<CAPTION>
1995 1994
------- -------
<S> <C> <C>
Products......................................................... $16,225 $11,307
Materials and supplies........................................... 26,539 31,921
------- -------
$42,764 $43,228
======= =======
</TABLE>
Inventories valued at LIFO amounted to $10,943 at December 31, 1995 and
$8,669 at December 31, 1994, which were below estimated replacement cost by $878
and $1,627, respectively.
NOTE 5 -- EQUITY INVESTMENT
At December 31, 1995 and 1994, an investment, accounted for using the
equity method, consisted of the following:
<TABLE>
<CAPTION>
1995 1994
-------- --------
<S> <C> <C>
Unimar Company................................................. $108,476 $114,505
======== ========
</TABLE>
The Company has a 50% interest in Unimar Company ("Unimar"), a partnership
through which the Company has an additional 11.56% working interest in the
Indonesian joint venture, resulting in a total working interest of 37.81%.
40
<PAGE> 43
UNION TEXAS PETROLEUM HOLDINGS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(DOLLARS IN THOUSANDS UNLESS OTHERWISE INDICATED)
The Company's share of selected financial data for its equity investee are
summarized as follows:
<TABLE>
<CAPTION>
1995 1994 1993
-------- ------- --------
<S> <C> <C> <C>
Net revenues........................................ $101,010 $98,963 $100,390
Gross profit........................................ 67,777 63,880 64,564
Net income reported by equity partnership........... $ 20,071 $16,552 $ 15,114
Other............................................... 800 3,892 (6,232)
-------- ------- --------
Net income of equity investee....................... $ 20,871 $20,444 $ 8,882
======== ======= ========
</TABLE>
<TABLE>
<CAPTION>
1995 1994
-------- --------
<S> <C> <C>
Current assets............................................. $ 12,754 $ 12,226
Total assets............................................... 203,607 211,090
Current liabilities........................................ 15,731 15,281
Partners' account.......................................... 102,533 109,124
</TABLE>
NOTE 6 -- PROPERTY, PLANT AND EQUIPMENT
At December 31, 1995 and 1994, property, plant and equipment consisted of
the following:
<TABLE>
<CAPTION>
1995 1994
---------- ----------
<S> <C> <C>
Land and land improvements................................ $ 12,635 $ 13,549
Oil and gas properties and equipment...................... 2,578,742 2,130,175
Plants and equipment...................................... 158,121 151,748
Other facilities.......................................... 10,683 24,978
Construction and wells in progress........................ 91,073 106,413
---------- ----------
2,851,254 2,426,863
Less -- accumulated depreciation, depletion and
amortization............................................ (1,300,056) (1,140,585)
---------- ----------
$1,551,198 $1,286,278
========== ==========
</TABLE>
In 1994, the Company acquired a 9.42% unit interest from Fina Exploration
Limited and Fina Petroleum Development Limited, subsidiaries of Petrofina SA
(collectively, "Fina") in two blocks in the undeveloped Britannia natural gas
and condensate field in the U.K. North Sea for 101 million pounds sterling ($159
million). Production from Britannia is planned to begin in late 1998. The
Company increased oil and gas properties and equipment by $219 million, the sum
of the purchase price of $159 million, and a deferred tax payable of $60 million
arising from the purchase. The purchase was financed with debt.
On July 18, 1995, the Company, through its subsidiary, Union Texas
Petroleum Limited ("UTPL"), acquired from Oryx UK Energy Company ("Oryx") their
15.5% working interest in Block 16/26 in the central United Kingdom North Sea,
which includes the Alba field. UTPL paid Oryx $270 million for the interest. The
effective date of the transaction was July 1, 1995. The Company funded the
acquisition under its bank credit facilities and its uncommitted and unsecured
lines of credit. The Company increased plant, property and equipment by $328
million, the sum of the purchase price of $270 million and a deferred tax
payable of $58 million arising from the purchase.
41
<PAGE> 44
UNION TEXAS PETROLEUM HOLDINGS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(DOLLARS IN THOUSANDS UNLESS OTHERWISE INDICATED)
NOTE 7 -- DEBT
At December 31, 1995 and 1994, long-term debt consisted of the following:
<TABLE>
<CAPTION>
1995 1994
-------- --------
<S> <C> <C>
Credit facilities...................................................... $132,000 $325,503
8.25% Senior Notes due November 15, 1999............................... 100,000 100,000
8 3/8% Senior Notes due 2005........................................... 125,000
8 1/2% Senior Notes due 2007........................................... 75,000
Medium Term Notes...................................................... 100,000
Britannia financing.................................................... 29,368
Subsidiary production loan............................................. 4,582 6,874
Money market lines of credit........................................... 148,474 106,032
-------- --------
714,424 538,409
Less -- portion due within one year.................................... (2,292) (2,292)
-------- --------
$712,132 $536,117
======== ========
</TABLE>
Credit Facilities
The Company had three unsecured credit facilities (the "Credit Facilities")
at December 31, 1995. One of the Credit Facilities is a $100 million unsecured
credit agreement with a syndicate of banks, that provides for conversion of
amounts outstanding on April 15, 1996 to a one-year term loan maturing April 15,
1997. Another Credit Facility is a $450 million unsecured credit agreement with
a syndicate of banks that provides for a quarterly reduction of $35 million
beginning July 31, 1998, with a final maturity of April 30, 1999. The $450
million revolver allows the Company to obtain up to $300 million of availability
thereunder in U.S. dollar loans that bear interest at a rate determined in a
competitive bid process. Loans under the $450 million revolver may be made in
both pounds sterling and U.S. dollars at the option of the Company. In June
1995, the Company entered into an additional $100 million unsecured credit
agreement with certain banks. This $100 million revolver providing for
conversion of amounts outstanding on June 15, 1996 to a one-year term loan
maturing June 15, 1997 was terminated January 31, 1996. Loans under the Credit
Facilities bear interest at floating market rates based on, at the Company's
option, the agent bank's base rate or LIBOR, plus applicable margins, subject to
increase in certain events. The Credit Facilities contain restrictive covenants,
including maintenance of certain coverage ratios related to the incurrence of
additional indebtedness and limitations on asset sales and mergers or
consolidations. The covenants also require maintenance of stockholders' equity,
as adjusted, of $350 million. At December 31, 1995, $132 million was outstanding
under the $450 million revolver bearing interest at a weighted average rate of
6.17% per annum. The Credit Facilities provide the Company with the ability to
borrow on a long-term basis, and as it is the Company's intent to do so, such
borrowings are classified as long-term.
Senior Notes
In March 1995, the Company publicly issued $125 million principal amount of
8 3/8% Senior Notes due 2005 (the "8 3/8% Senior Notes") at an initial public
offering price of 99.431%. In April 1995, the Company publicly issued $75
million principal amount of 8 1/2% Senior Notes due 2007 (the "8 1/2% Senior
Notes") at an initial public offering price of 99.658%. The net proceeds from
the sale of the 8 3/8% Senior Notes and the 8 1/2% Senior Notes were
approximately $123.5 million and $74.2 million, respectively (after deducting
underwriting discount, commissions and offering expenses). The Company used such
proceeds to reduce debt under its existing credit facility and its uncommitted
and unsecured lines of credit. The Company's $100 million
42
<PAGE> 45
UNION TEXAS PETROLEUM HOLDINGS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(DOLLARS IN THOUSANDS UNLESS OTHERWISE INDICATED)
principal amount of 8.25% Senior Notes due 1999 ("the 8.25% Senior Notes")
discussed below together with the 8 1/2% Senior Notes and the 8 3/8% Senior
Notes are referred to herein as the "Senior Notes."
In November 1992, the Company sold $100 million principal amount, at an
initial offering price of 99.424%, of 8.25% Senior Notes for approximately $98
million (after deducting underwriting discounts, commission and offering
expenses). The Company used such proceeds to reduce then outstanding debt under
its credit facility. The Senior Notes represent general unsecured obligations of
the Company and rank pari passu in right of payment with the Company's
obligations under its Credit Facilities and senior in right of payment to any
future subordinated indebtedness of the Company. Each of the Senior Notes
contain similar restrictive covenants. The Senior Notes are redeemable at any
time, at the option of the Company, in whole or in part, at a price equal to
100% of the principal amount plus accrued interest plus a make-whole premium
relating to the then-prevailing Treasury Yield and the remaining life of the
Senior Notes.
Medium Term Notes
During 1995, the Company issued $100 million aggregate principal amount of
medium term notes ("MTN") with terms of seven and twelve years and interest
rates varying from 6.51% to 6.81%. The net proceeds from the sale of the MTN
were approximately $99.4 million and were used to reduce debt under the
Company's credit facility and its uncommitted and unsecured lines of credit.
These MTN represent general unsecured obligations of the Company and rank pari
passu in right of payment with the Company's obligations under its Credit
Facilities and Senior Notes and senior in right of payment to any future
subordinated indebtedness of the Company. Each of the MTN contain similar
restrictive covenants as the Senior Notes. The MTN are redeemable at any time,
at the option of the Company, in whole or in part, at a price equal to 100% of
the principal amount plus accrued interest plus a make-whole premium relating to
the then-prevailing Treasury Yield and the remaining life of the MTN.
Britannia Financing
The Company's indirect subsidiary, Union Texas Britannia Limited ("UTBL"),
which is a wholly owned subsidiary of UTPL, has a 150 million pounds sterling
secured financing from a syndicate of banks. The financing is used to fund the
Company's share of the cost of developing the Britannia field to production
(including interest and other financing costs incurred prior to completion and
potential cost overruns), and any remaining availability after completion may,
subject to certain coverage ratios being met, be used for UTBL's general
corporate purposes. Except for certain support by UTPL related to any potential
cost overruns in excess of the facility amount (limited to 30 million pounds
sterling), insurance, tax benefits and administrative services, the lenders'
recourse will be limited to the Britannia field project assets and is
nonrecourse to the Company. The financing has a final maturity in September
2005. At December 31, 1995, 19 million pounds sterling ($29 million) was
outstanding under UTBL's financing.
Subsidiary Production Loan
Union Texas Pakistan, Inc., a wholly owned subsidiary of the Company, has a
nonrecourse loan, payable from production proceeds, which will be repaid in
semiannual installments of $1,146 through 1997, and bears interest at the
182-day Treasury bill rate plus 1.0%. At December 31, 1995, such interest rate
was 6.64%.
Money Market Lines of Credit
Due to the Company's ability to obtain favorable interest rates on
short-term borrowings, uncommitted and unsecured lines of credit were
established with several banks in both U.S. dollars and pounds sterling. These
money market borrowings, which have a short-term maturity, have been classified
as long-term debt based on the Company's intent to refinance these borrowings
for a period exceeding one year and the ability to refinance them on a long-term
basis through its Credit Facilities. At December 31, 1995 and 1994,
43
<PAGE> 46
UNION TEXAS PETROLEUM HOLDINGS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(DOLLARS IN THOUSANDS UNLESS OTHERWISE INDICATED)
$148 million and $106 million, respectively, were outstanding under these money
market lines which bore interest at weighted average rates of 6.5% and 6.46% per
annum, respectively. At December 31, 1995, the Company has adjusted the 1994
balance sheet by reclassifying outstanding money market borrowings of $106
million from current liabilities to long-term debt. Management believes that
this presentation is more meaningful for comparative analysis and appropriately
reflects management's intent at December 31, 1994.
Interest capitalized for the years 1995, 1994, and 1993 was $23,081,
$18,774, and $25,674, respectively.
Scheduled maturities of long-term debt outstanding during the five years
1996 through 2000 are $2,292, $2,290, $0, $395,933 and $13,909, respectively.
NOTE 8 -- INCOME TAXES
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------
1995 1994 1993
-------- -------- ---------
<S> <C> <C> <C>
United States (Current):
Federal........................................... $ 2,935 $ 3,756 $ 1,543
State............................................. 4,767 4,713 1,616
-------- --------- ----------
7,702 8,469 3,159
-------- --------- ----------
Foreign:
Current........................................... 162,851 148,738 100,648
Deferred.......................................... (19,576) (11,962) (107,493)
-------- --------- ----------
143,275 136,776 (6,845)
-------- --------- ----------
$150,977 $145,245 $ (3,686)
======== ========= ==========
</TABLE>
A deferred tax liability or asset is recorded for future tax consequences
arising from differences between the financial accounting and tax basis of the
assets and liabilities of the Company. An impairment evaluation, with reserves
recorded as necessary for any tax benefit not expected to be realized, is
required of deferred tax assets. Deferred tax liabilities or assets are adjusted
for changes in income tax laws or rates when enacted. Deferred tax expense or
benefit is derived from changes in deferred tax liabilities or assets. A current
tax expense or benefit is recognized for the estimated taxes payable or
refundable on tax returns for the current year.
Under the corporate alternative minimum tax ("AMT"), the Company's U.S. tax
liability is the greater of its regular tax or the AMT. To the extent that the
Company's AMT liability exceeds its otherwise determined tax liability, an AMT
credit may be generated and this credit may be applied against future tax
liabilities.
The principal items accounting for the difference in taxes on income
computed at the United States statutory rate and as recorded are as follows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------
1995 1994 1993
-------- -------- --------
<S> <C> <C> <C>
Computed tax at 35% of pretax income................. $ 88,664 $ 74,194 $ 9,444
Rate change in the U.K. for PRT...................... (50,200)
Taxes in excess of the U.S. tax rate on foreign
earnings........................................... 56,353 52,270 10,467
Alternative Minimum Tax.............................. 2,935 3,756 1,543
Domestic operating losses generating no tax
benefit............................................ 10,313 23,445
All other items, net................................. 3,025 4,712 1,615
-------- -------- --------
$150,977 $145,245 $ (3,686)
======== ======== ========
</TABLE>
Effective July 1, 1993, the British Parliament enacted changes in the U.K.
Petroleum Revenue Tax ("PRT"). These changes included reducing PRT on producing
fields in the U.K. North Sea from 75% to 50% and abolishing PRT for all new
fields not licensed for development on March 16, 1993. Accordingly, in 1993,
44
<PAGE> 47
UNION TEXAS PETROLEUM HOLDINGS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(DOLLARS IN THOUSANDS UNLESS OTHERWISE INDICATED)
the Company reduced its liability for U.K. deferred income taxes and recorded a
one-time benefit to net income of approximately $50 million.
Deferred tax liabilities (assets) are comprised of the effects of temporary
differences as follows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------
1995 1994
-------- --------
<S> <C> <C>
Gross deferred tax liabilities:
Property differences pertaining to depreciation and other
expenditures................................................ $399,665 $369,037
Acquisitions................................................... 57,858 60,466
Gross deferred tax assets:
U.K. Corporation Tax effect of deferred Petroleum Revenue
Tax......................................................... (29,537) (32,998)
Dismantlement and removal provision............................ (32,697) (30,728)
-------- --------
$395,289 $365,777
======== ========
</TABLE>
NOTE 9 -- PENSION BENEFITS
The Union Texas Petroleum Salaried Employees' Pension Plan (the "Pension
Plan") covers substantially all employees. Plan benefits are generally based on
years of service and an employee's compensation levels during the last years of
employment. The Company's funding policy is to contribute annually an amount at
least equal to the minimum funding requirement of the Employee Retirement Income
Security Act of 1974.
The Union Texas Petroleum Supplemental Retirement Plans ("Supplemental
Retirement Plans") cover certain employees whose pension benefits were affected
by changes in the Internal Revenue Code of 1986, as amended, and certain other
benefit limitations of the Internal Revenue Code. The supplemental plans are
unfunded.
The Pension Plan has assets in excess of the projected benefit obligation
for 1995. The assets of this plan are held by trustees and are invested in
common stock, fixed rate and real estate investments. The following table sets
forth the plans' funded status at December 31, 1995 and 1994:
<TABLE>
<CAPTION>
SUPPLEMENTAL
PENSION PLAN RETIREMENT PLANS
-------------------- ------------------
1995 1994 1995 1994
-------- -------- ------- -------
<S> <C> <C> <C> <C>
Actuarial present value of benefit
obligations:
Vested benefits........................... $122,084 $109,074 $ 4,050 $ 3,753
Nonvested benefits........................ 4,464 4,083 207 75
-------- -------- ------- -------
Total accumulated benefit
obligation...................... 126,548 113,157 4,257 3,828
Amounts related to projected pay
increases.............................. 9,288 7,572 1,856 660
-------- -------- ------- ------
Total projected benefit
obligation...................... 135,836 120,729 6,113 4,488
Net assets available for plan benefits held
by trustees............................... 142,742 116,731
-------- -------- ------- ------
Net assets over (under) projected benefit
obligation................................ 6,906 (3,998) (6,113) (4,488)
Unrecognized net obligation at the date of
initial application of FAS 87 (1/1/86).... 1,657 1,988
Unrecognized prior service cost............. 3,220 3,633 1,323 1,665
Adjustment required to recognize minimum
liability................................. (2,058) (2,205)
Unrecognized net (gain) loss................ (7,807) (833) 2,591 1,200
-------- -------- ------- -------
Prepaid pension cost (pension
liability)............................. $ 3,976 $ 790 $(4,257) $(3,828)
======== ======== ======= =======
</TABLE>
45
<PAGE> 48
UNION TEXAS PETROLEUM HOLDINGS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(DOLLARS IN THOUSANDS UNLESS OTHERWISE INDICATED)
Net periodic pension cost for 1995, 1994 and 1993 included the following
components:
<TABLE>
<CAPTION>
1995 1994 1993
--------- --------- ---------
<S> <C> <C> <C>
Service cost-benefits earned during the period..... $ 2,310 $ 2,474 $ 2,286
Interest cost on projected benefit obligation...... 10,469 10,173 10,825
Return on plan assets.............................. (30,625) 477 (12,070)
Net amortization and deferral...................... 22,560 (9,381) 2,468
--------- --------- ---------
Net periodic pension cost before effect of
settlement loss.................................. 4,714 3,743 3,509
Settlement loss.................................... 596 610
--------- --------- ---------
Net periodic pension cost.......................... $ 4,714 $ 4,339 $ 4,119
========= ========= =========
</TABLE>
Settlement losses resulted from certain lump sum payments to employees who
terminated from participation in the Supplemental Retirement Plans during the
year.
The assumed average rate of return on plan assets was 8% in 1995, 1994 and
1993 for the plans. Measurement of the projected benefit obligation was based on
an assumed discount rate of 7.25% and 7% in 1995, 8.5% and 7% in 1994 and 7.5%
and 7% in 1993 for normal and lump sum eligible participants, respectively, for
the Pension and Supplemental Retirement Plans and an assumed long-term rate of
compensation increase of 4.5%, 4.5% and 5% for the Pension and Supplemental
Retirement Plans in 1995, 1994 and 1993, respectively.
NOTE 10 -- OTHER POSTRETIREMENT BENEFITS
The Company currently provides postretirement benefits, principally health
care and life insurance benefits, for employees. Under the Company's current
policy, substantially all of the Company's employees may become eligible for
those benefits if they reach normal retirement age with ten years of service
while working for the Company. These benefits are unfunded.
The following table sets forth the plan's status at December 31:
<TABLE>
<CAPTION>
1995 1994
-------- --------
<S> <C> <C>
Accumulated postretirement benefit obligation:
Retirees' benefits........................................... $ 31,481 $ 26,060
Other fully eligible participants' benefits.................. 5,247 3,721
Other active plan participants' benefits..................... 7,128 4,587
-------- --------
Accumulated postretirement benefit obligation............. (43,856) (34,368)
Unrecognized amounts:
Prior service cost........................................ (11,885) (15,306)
Net loss.................................................. 17,136 9,114
-------- --------
Accrued obligation............................................. $(38,605) $(40,560)
======== ========
</TABLE>
Net postretirement benefit cost for 1995, 1994 and 1993 included the
following components:
<TABLE>
<CAPTION>
1995 1994 1993
------- ------- -------
<S> <C> <C> <C>
Service cost-benefits earned during the period.......... $ 503 $ 497 $ 393
Interest cost on projected benefit obligation........... 3,117 2,735 2,743
Net amortization........................................ (3,136) (3,051) (3,138)
------- ------- -------
Net postretirement benefit cost......................... $ 484 $ 181 $ (2)
======= ======= =======
</TABLE>
46
<PAGE> 49
UNION TEXAS PETROLEUM HOLDINGS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(DOLLARS IN THOUSANDS UNLESS OTHERWISE INDICATED)
Measurement of the accumulated postretirement benefit obligation was based
on an assumed discount rate of 7.25% for 1995, 8.5% for 1994 and 7.5% for 1993.
For measurement purposes, a 12%, 12.75% and 13.5% annual rate of increase in the
per capita cost of covered health care benefits for those age 65 and older were
assumed for 1995, 1994 and 1993, respectively; the rate was assumed to decrease
linearly to 6% for 2003 and after. The health care cost trend rate assumption
has a significant effect on the amounts reported. Increasing the assumed health
care cost trend rates by 1% in each year would increase the accumulated
postretirement benefit obligation as of December 31, 1995 and 1994, by $1,988
and $1,451, respectively. Additionally, it would increase the aggregate of the
service and interest cost components of net periodic postretirement benefit cost
for the years ended December 31, 1995, 1994 and 1993 by $216, $176 and $151,
respectively.
NOTE 11 -- STOCK OPTIONS
Under the terms of the 1994 Incentive Plan, the Company has authorized the
issuance of options to employees and certain members of the board of directors
to purchase up to 4 million shares of common stock. Options are exercisable for
a maximum period of ten years at an exercise price of not less than the fair
market value of the underlying common stock at the time of grant. In 1995,
20,000 and 12,000 options at $18.625 and $22.4375 per share, respectively, were
granted to certain directors. These options are 100% vested. The options granted
to employees vest at 25% per annum. Options to purchase 896,200 shares at
$18.0625 per share were granted to employees in 1995. Certain officers have been
granted nonqualified options and incentive stock options with appreciation
rights. At December 31, 1995, options outstanding with respect to 210,500 shares
of common stock have appreciation rights attached. Following the adoption of the
1994 Incentive Plan during 1995, all further stock option grants will be made
under the 1994 Incentive Plan only.
Under the terms of the 1992 Stock Option Plan, the Company authorized the
issuance of options to employees to purchase up to 4 million shares of common
stock. Options are exercisable for a maximum period of ten years at an exercise
price of not less than the fair market value of the underlying common stock at
the time of the grant. Options granted prior to 1994 vest at 20% per annum.
Options granted in 1994 vest at 25% per annum. Certain officers have been
granted nonqualified options and incentive stock options with appreciation
rights. At December 31, 1995, options outstanding with respect to 768,900 shares
of common stock have appreciation rights attached.
<TABLE>
<CAPTION>
NUMBER OF SHARES
---------------------
1995 1994
--------- --------
<S> <C> <C>
Outstanding at beginning of year.............................. 2,643,380 1,778,710
Granted at $18.75 per share................................... 960,900*
Less:
Exercised at $18.3125 to $20.875 per share.................. 56,460 6,460
Canceled.................................................... 93,670 89,770
--------- ---------
Outstanding at end of year at $18.3125 to $20.875 per share... 2,493,250 2,643,380
========= =========
</TABLE>
- ---------------
*298,700 shares granted in 1994 were granted with stock appreciation rights.
47
<PAGE> 50
UNION TEXAS PETROLEUM HOLDINGS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(DOLLARS IN THOUSANDS UNLESS OTHERWISE INDICATED)
Under the terms of the 1985 Stock Option Plan (the "1985 Plan"), the
Company authorized the issuance of options to officers and key employees to
purchase up to 4,466,667 shares of common stock. Options are exercisable for a
maximum period of ten years at an exercise price of not less than the fair
market value of the underlying common stock at the time of the grant. Certain
officers and employees have been granted options with appreciation rights. All
options granted are fully vested. At December 31, 1995, options outstanding with
respect to 368,409 shares of common stock have appreciation rights attached.
<TABLE>
<CAPTION>
NUMBER OF SHARES
--------------------
1995 1994
-------- --------
<S> <C> <C>
Outstanding at beginning of year................................. 616,352 714,976
Less:
Exercised at $7.50 to $16.125 per share........................ 68,192 98,624
------- -------
Outstanding at end of year at $7.50 to $16.125 per share......... 548,160 616,352
======= =======
</TABLE>
Under the terms of the 1987 Stock Option Plan, the Company authorized the
issuance of options to purchase up to 1,333,333 shares of common stock to
certain employees not covered under the 1985 Plan. Options are exercisable for a
maximum period of ten years at an exercise price of not less than the fair
market value of the underlying common stock at the time of grant. The options
vest at 20% per annum.
<TABLE>
<CAPTION>
NUMBER OF SHARES
--------------------
1995 1994
-------- --------
<S> <C> <C>
Outstanding at beginning of year................................. 275,664 326,022
Less:
Exercised at $12.25 to $16.125 per share....................... 39,622 44,810
Canceled....................................................... 1,057 5,548
------- -------
Outstanding at end of year at $12.25 to $16.125 per share........ 234,985 275,664
======= =======
</TABLE>
In October 1995, the Financial Accounting Standards Board released
Statement of Financial Accounting Standards No. 123, "Accounting for Stock-Based
Compensation," which establishes financial and reporting standards for stock
based employee compensation plans that will be effective for the Company's 1996
financial statements. The statement encourages, but does not require, companies
to adopt a fair value based method of accounting for such plans in place of
current accounting standards. Companies electing to continue to use their
existing accounting methods will be required to make pro forma disclosures of
net income assuming a fair value based method of accounting has been applied.
The Company is evaluating the Statement as to whether to adopt the fair value
based method of accounting or continue using its current accounting methods with
additional disclosures.
NOTE 12 -- MAJOR CUSTOMERS
During 1995, the Company's U.K. operations had sales to B.P. Oil
International Limited and Elf Trading, in the amount of $107,891 and $109,067,
or 13% and 13%, respectively, of the Company's total sales and operating
revenues. During 1994, the Company's U.K. operations had sales to B.P. Oil
International Limited and Elf Trading, in the amount of $81,292 and $80,578, or
11% and 11%, respectively, of total sales and operating revenues. During 1993,
the Company's U.K. operations had sales to B.P. Oil International Limited, in
the amount of $89,098 or 13% of total sales and operating revenues.
48
<PAGE> 51
UNION TEXAS PETROLEUM HOLDINGS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(DOLLARS IN THOUSANDS UNLESS OTHERWISE INDICATED)
NOTE 13 -- SEGMENT FINANCIAL DATA
<TABLE>
<CAPTION>
EXPLORATION AND PRODUCTION
------------------------------------------------------ PETRO-
UNITED OTHER CHEM-
STATES UNITED INTER- ICALS
(ALASKA) KINGDOM INDONESIA PAKISTAN NATIONAL (A) OTHER(A) TOTAL
------- ------- --------- -------- -------- ------ -------- -----
(DOLLARS IN MILLIONS)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
1995
Sales and operating revenues....... $ 323 $ 276 $ 51 $ 1 $ 200 $ 1 $ 852
====== ===== ===== ===== ===== ===== ======
Operating profit (loss)............ $ (6) 84 178 19 (49) 62 (5) 283
Interest income.................... 2 1 1 4
General and administrative
expenses......................... (26) (26)
Interest expense................... (6) (1) (22) (29)
Net income of equity investee...... 21 21
---- ------ ----- ----- ----- ----- ----- ------
Income (loss) before income
taxes............................ (6) 80 200 18 (49) 62 (52) 253
Income taxes....................... 34 105 4 24 (16) 151
---- ------ ----- ----- ----- ----- ----- ------
Net income (loss).................. $ (6) $ 46 $ 95 $ 14 $ (49) $ 38 $ (36) $ 102
==== ====== ===== ===== ===== ===== ===== ======
Identifiable assets................ $ 13 $1,168 $ 459 $ 46 $ 9 $ 111 $ 31 $1,837
Capital additions.................. 6 353 30 10 2 7 1 409
Depreciation, depletion and
amortization..................... 139 35 7 4 5 2 192
1994
Sales and operating revenues....... $ 260 $ 278 $ 39 $ 1 $ 169 $ 1 $ 748
====== ===== ===== ===== ===== ===== ======
Operating profit (loss)............ $ (7) $ 57 $ 174 $ 13 $ (25) $ 24 $ (10) $ 226
Interest income.................... 1 1
General and administrative
expenses......................... (24) (24)
Interest expense................... 1 (12) (11)
Net income (loss) of equity
investee......................... 21 (1) 20
---- ------ ----- ----- ----- ----- ----- ------
Income (loss) before income
taxes............................ (7) 59 195 13 (25) 24 (47) 212
Income taxes....................... 32 101 3 9 145
---- ------ ----- ----- ----- ----- ----- ------
Net income (loss).................. $ (7) $ 27 $ 94 $ 10 $ (25) $ 15 $ (47) $ 67
==== ====== ===== ===== ===== ===== ===== ======
Identifiable assets................ $ 8 $ 887 $ 473 $ 40 $ 11 $ 108 $ 18 $1,545
Capital additions.................. 2 219 31 9 8 6 1 276
Depreciation, depletion and
amortization..................... 2 114 37 7 2 5 2 169
1993
Sales and operating revenues....... $ 208 $ 279 $ 49 $ 1 $ 145 $ 682
====== ===== ===== ===== ===== ===== ======
Operating profit (loss)............ $(34) $ (83) $ 164 $ 24 $ (26) $ 8 $ (8) $ 45
Interest income.................... 2 1 2 5
General and administrative
expenses......................... (24) (24)
Interest expense................... (1) (1) (4) (6)
Preferred dividends of a
subsidiary....................... (2) (2)
Net income (loss) of equity
investee......................... 14 (5) 9
---- ------ ----- ----- ----- ----- ----- ------
Income (loss) before income taxes
and cumulative effect of change
in accounting principle.......... (34) (82) 179 23 (26) 8 (41) 27
Income taxes (benefit)............. (105) 90 7 3 1 (4)
---- ------ ----- ----- ----- ----- ----- ------
Cumulative effect of change in
accounting principle............. (4) (4)
---- ------ ----- ----- ----- ----- ----- ------
Net income (loss).................. $(34) $ 23 $ 89 $ 16 $ (26) $ 5 $ (46) $ 27
==== ====== ===== ===== ===== ===== ===== ======
Identifiable assets................ $ 8 $ 695 $ 476 $ 37 $ 5 $ 91 $ 27 $1,339
Capital additions.................. (9) 94 46 5 4 1 141
Depreciation, depletion and
amortization..................... 2 193 36 6 5 1 243
</TABLE>
- ---------------
(a) Petrochemicals operations and Other represent United States activities.
49
<PAGE> 52
UNION TEXAS PETROLEUM HOLDINGS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(DOLLARS IN THOUSANDS UNLESS OTHERWISE INDICATED)
NOTE 14 -- COMMITMENTS
The Company has entered into various commitments and operating agreements
related to the development of and production from certain proved oil and gas
properties. Also during the normal course of business, the Company has issued
various letters of credit, bank guarantees and performance bonds, which at
December 31, 1995, totaled $8 million. At December 31, 1995, the Company had
open foreign exchange contracts with a net value of 21 million pounds sterling.
These contracts hedge economic exposures, based on the Company's assessment of
its net exposure to changes in foreign currency rates. It is management's belief
that such commitments and guarantees will be met without material adverse effect
on the Company's financial position.
The amounts of operating lease obligations due during the five years 1996
through 2000 are $8,042, $7,866, $7,732, $7,641 and $7,050, respectively.
Rental expense for the years 1995, 1994 and 1993 was $9,379, $9,520 and
$8,339, respectively.
NOTE 15 -- CONTINGENCIES
The Company and its subsidiaries and related companies are named defendants
in a number of lawsuits and named parties in numerous governmental proceedings
arising in the ordinary course of business.
While the outcome of such contingencies, lawsuits or other proceedings
against the Company cannot be predicted with certainty, management expects that
such liability, to the extent not provided for through insurance or otherwise,
will not have a material adverse effect on the financial statements of the
Company.
NOTE 16 -- SUPPLEMENTARY QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
<TABLE>
<CAPTION>
1995 1994
QUARTER ENDED QUARTER ENDED
----------------------------------------------------- -----------------------------------------------------
MAR. 31 JUNE 30 SEPT. 30 DEC. 31 YEAR MAR. 31 JUNE 30 SEPT. 30 DEC. 31 YEAR
-------- -------- --------- -------- -------- -------- -------- --------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Net sales and
operating
revenues........ $239,558 $200,425 $197,255 $214,363 $851,601 $194,097 $145,608 $193,707 $214,471 $747,883
Gross profit...... 117,080 90,736 77,391 87,858 373,065 84,578 48,648 75,193 74,253 282,672
Net income........ 46,677 20,102 11,723 23,848 102,350 26,615 8,296 14,641 17,186 66,738
Per share of
common stock:
Net earnings...... .53 .23 .13 .27 1.17 .30 .09 .17 .20 .76
Dividends......... .05 .05 .05 .05 .20 .05 .05 .05 .05 .20
Market price:
High.............. 23 1/8 23 7/8 21 1/2 19 7/8 23 7/8 22 20 1/8 20 3/8 21 7/8 22
Low............... 18 1/4 21 18 17 1/8 17 1/8 16 5/8 16 1/4 17 18 1/8 16 1/4
</TABLE>
- ---------------
Source of Market Prices: New York Stock Exchange Composite Transactions Tape
NOTE 17 -- SUPPLEMENTARY OIL AND GAS INFORMATION
Reserve estimation -- (Unaudited)
Oil and gas reserves cannot be measured exactly. Reserve estimates are
based on many factors related to reservoir performance which require evaluation
by the engineers interpreting the available data, as well as price, costs and
other economic factors. The reliability of these estimates at any point in time
depends on both the quality and quantity of the technical and economic data, the
production performance of the reservoirs as well as extensive engineering
judgment. Consequently, reserve estimates are subject to revision as additional
data becomes available during the producing life of a reservoir. When a
commercial reservoir is discovered,
50
<PAGE> 53
UNION TEXAS PETROLEUM HOLDINGS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(DOLLARS IN THOUSANDS UNLESS OTHERWISE INDICATED)
proved reserves are initially determined based on only limited data from the
first well or wells. Further drilling may better define the extent of the
reservoir and additional production performance, well tests and engineering
studies will likely improve the reliability of the estimate.
Reserves are considered proved if economic producibility is supported by
either actual production or conclusive formation tests. Proved developed
reserves are reserves that can be expected to be recovered through existing
wells with existing equipment and operating methods. Proved undeveloped reserves
are reserves that are expected to be recovered from new wells on undrilled
acreage or from existing wells where a relatively significant expenditure is
required to permit production. These estimates do not include reserves which may
be found by extension of proved areas or reserves recoverable by secondary or
tertiary recovery methods unless these methods are in operation and showing
successful results.
In 1995, the Company purchased an interest in the Alba field in the U.K.
North Sea, adding at July 1, 1995, 45 million barrels of oil equivalent ("boe").
In 1994, the Company purchased an interest in the undeveloped Britannia
field in the U.K. North Sea, adding at year end 1994, 38 million boe to its
proved reserves.
Information presented for the Company's operations in Indonesia relates to
a production sharing contract between a joint venture group in which the Company
is a member and Pertamina. Debt service relating to the Indonesian facility
which liquefies natural gas supplied by the joint venture and other production
sharing contractors is accounted for by the Company as a cost of production and
operation. The debt obligation is non-recourse to the Company. Such debt service
is deducted in estimating future net revenues to be distributed among Pertamina
and the production sharing contractors including the joint venture and the
Company's interest therein. The joint venture has no ownership interest in the
oil and gas reserves but does have the right to share revenues and/or production
and is entitled to recover most field and other operating costs and capital
depreciation. The reserve estimates, which are based on year-end prices, are
subject to revision as product prices and costs fluctuate due to the cost
recovery feature under the production sharing contract and due to the effect
that price fluctuations generally have on reserve estimates. The impact on
reserves is inversely related to price changes and directly related to changes
in field operating and capital costs. Indonesian reserves associated with the
Unimar partnership are shown under the caption "Non-Consolidated Interests."
Prior to 1993, the Company included in its reported estimates of proved
reserves attributable to its interest in the Indonesian joint venture only those
proved reserves that were committed to be sold under LNG sales contracts or
which the Company expected to be sold in the spot market. Over the past several
years, the Indonesian joint venture experienced better than anticipated field
performance and development drilling successes. Also, Pertamina made progress in
marketing additional LNG volumes that the Company believes will be sold. As a
result, beginning in 1993, the Company booked upward revisions of proved
reserves attributable to its interest in this joint venture.
"Other International" represents an interest in Egypt.
51
<PAGE> 54
UNION TEXAS PETROLEUM HOLDINGS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(DOLLARS IN THOUSANDS UNLESS OTHERWISE INDICATED)
The Company's net quantities of proved developed and undeveloped reserves
of oil and natural gas, by geographic areas and changes therein, were as
follows:
ESTIMATED QUANTITIES OF NET PROVED CRUDE OIL AND NATURAL GAS LIQUIDS RESERVES
<TABLE>
<CAPTION>
CONSOLIDATED SUBSIDIARIES
-------------------------------------------------------- NON-
UNITED OTHER CONSOLIDATED TOTAL
KINGDOM INDONESIA PAKISTAN INTERNATIONAL TOTAL INTERESTS WORLDWIDE
------- --------- -------- ------------- ------- ------------ ---------
(THOUSANDS OF BARRELS)
<S> <C> <C> <C> <C> <C> <C> <C>
YEAR ENDED DECEMBER 31, 1995
Net proved reserves
-- beginning of year................. 73,862 19,142 3,842 32 96,878 7,571 104,449
-- revisions of previous estimates... 1,995 1,894 1,275 9 5,173 832 6,005
-- purchase of minerals in place..... 45,012 45,012 45,012
-- extensions, discoveries and other
additions........................ 1,261 1,261 1,261
-- production........................ (15,155) (2,094) (1,995) (22) (19,266) (692) (19,958)
------- ------- -------- ------- ------- ------- -------
Net proved reserves
-- end of year....................... 105,714 18,942 4,383 19 129,058 7,711 136,769
======= ======= ======== ======= ======= ======= =======
Net proved developed reserves
-- beginning of year................. 56,773 17,247 2,714 32 76,766 6,835 83,601
-- end of year....................... 67,147 17,041 3,215 19 87,422 6,926 94,348
YEAR ENDED DECEMBER 31, 1994
Net proved reserves
-- beginning of year................. 69,199 17,779 4,660 35 91,673 6,809 98,482
-- revisions of previous estimates... 8,818 3,371 699 48 12,936 1,426 14,362
-- extensions, discoveries and other
additions........................ 278 278 278
-- purchase of minerals in place..... 9,241 9,241 9,241
-- production........................ (13,396) (2,008) (1,795) (51) (17,250) (664) (17,914)
------- ------- -------- ------- ------- ------- -------
Net proved reserves
-- end of year...................... 73,862 19,142 3,842 32 96,878 7,571 104,449
======= ======= ======== ======= ======= ======= =======
Net proved developed reserves
-- beginning of year................. 33,709 14,503 3,293 35 51,540 5,557 57,097
-- end of year....................... 56,773 17,247 2,714 32 76,766 6,835 83,601
YEAR ENDED DECEMBER 31, 1993
Net proved reserves
-- beginning of year................. 76,098 13,380 5,467 26 94,971 4,866 99,837
-- revisions of previous estimates... 3,212 6,464 505 56 10,237 2,626 12,863
-- extensions, discoveries and other
additions........................ 594 594 594
-- production........................ (10,111) (2,065) (1,906) (47) (14,129) (683) (14,812)
------- ------- ------- ------- ------- ------- -------
Net proved reserves
-- end of year....................... 69,199 17,779 4,660 35 91,673 6,809 98,482
======= ======= ======== ======= ======= ======= =======
Net proved developed reserves
-- beginning of year................. 24,789 12,223 3,054 26 40,092 4,438 44,530
-- end of year....................... 33,709 14,503 3,293 35 51,540 5,557 57,097
</TABLE>
52
<PAGE> 55
UNION TEXAS PETROLEUM HOLDINGS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(DOLLARS IN THOUSANDS UNLESS OTHERWISE INDICATED)
ESTIMATED QUANTITIES OF NET PROVED NATURAL GAS RESERVES
<TABLE>
<CAPTION>
CONSOLIDATED SUBSIDIARIES
------------------------------------------------ NON-
UNITED CONSOLIDATED TOTAL
KINGDOM INDONESIA PAKISTAN TOTAL INTERESTS WORLDWIDE
------- --------- -------- --------- ------------ ---------
(MILLIONS OF CUBIC FEET)
<S> <C> <C> <C> <C> <C> <C>
YEAR ENDED DECEMBER 31, 1995
Net proved reserves
-- beginning of year................... 319,621 972,796 97,895 1,390,312 385,834 1,776,146
-- revisions of previous estimates..... 37,079 19,270 24,976 81,325 10,228 91,553
-- extensions, discoveries and other
additions.......................... 14,952 14,952 14,952
-- production.......................... (12,568) (93,692)(a) (16,401) (122,661) (30,983)(a) (153,644)
------- --------- ------- --------- ------- ---------
Net proved reserves
-- end of year......................... 344,132 898,374(a) 121,422 1,363,928 365,079(a) 1,729,007
======= ========= ======= ========= ======= =========
Net proved developed reserves
-- beginning of year................... 149,301 812,933 51,883 1,014,117 320,502 1,334,619
-- end of year......................... 139,413 758,942 58,642 956,997 307,102 1,264,099
YEAR ENDED DECEMBER 31, 1994
Net proved reserves
-- beginning of year................... 139,195 1,008,863 101,753 1,249,811 389,670 1,639,481
-- revisions of previous estimates..... 6,625 63,381 3,303 73,309 29,054 102,363
-- extensions, discoveries and other
additions.......................... 15,673 8,618 24,291 24,291
-- purchase of minerals in place....... 166,828 166,828 166,828
-- production.......................... (8,700) (99,448)(a) (15,779) (123,927) (32,890)(a) (156,817)
------- --------- ------- --------- ------- ---------
Net proved reserves
-- end of year......................... 319,621 972,796(a) 97,895 1,390,312 385,834(a) 1,776,146
======= ========= ======= ========= ======= =========
Net proved developed reserves
-- beginning of year................... 131,002 785,135 38,784 954,921 299,768 1,254,689
-- end of year......................... 149,301 812,933 51,883 1,014,117 320,502 1,334,619
YEAR ENDED DECEMBER 31, 1993
Net proved reserves
-- beginning of year................... 89,774 797,988 101,032 988,794 295,184 1,283,978
-- revisions of previous estimates..... 52,166 301,278 (579) 352,865 124,383 477,248
-- extensions, discoveries and other
additions.......................... 16,840 16,840 16,840
-- production.......................... (2,745) (90,403)(a) (15,540) (108,688) (29,897)(a) (138,585)
------- --------- ------- --------- ------- ---------
Net proved reserves
-- end of year......................... 139,195 1,008,863(a) 101,753 1,249,811 389,670(a) 1,639,481
======= ========= ======= ========= ======= =========
Net proved developed reserves
-- beginning of year................... 74,658 725,490 34,542 834,690 267,085 1,101,775
-- end of year......................... 131,002 785,135 38,784 954,921 299,768 1,254,689
</TABLE>
- ---------------
(a) Includes gas consumed in the operation of the LNG plant, which was
approximately 11 Bcf and 4 Bcf, 11 Bcf and 4 Bcf and 10 Bcf and 4 Bcf
attributable to the Company and its Unimar partnership, respectively, for
1995, 1994 and 1993; and gas sold to fertilizer plants and a refinery.
53
<PAGE> 56
UNION TEXAS PETROLEUM HOLDINGS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(DOLLARS IN THOUSANDS UNLESS OTHERWISE INDICATED)
Costs incurred and results of operations
Costs incurred in oil and gas property acquisition, exploration and
development activities whether expensed or capitalized were as follows:
<TABLE>
<CAPTION>
CONSOLIDATED SUBSIDIARIES
--------------------------------------------------------
UNITED OTHER NON- TOTAL
STATES UNITED INTER- CONSOLIDATED WORLD-
(ALASKA) KINGDOM INDONESIA PAKISTAN NATIONAL TOTAL INTERESTS WIDE
--------- ------- --------- -------- -------- ----- ------------ ------
(DOLLARS IN MILLIONS)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Property acquisition (proved and
unproved)
1995.............................. $ 1 $ 275 $ 2 $ 278 $278
1994.............................. 3 159 7 169 169
1993.............................. 1 1 1
Exploration
1995.............................. 10 10 $ 8 $ 11 46 85 85
1994.............................. 4 14 9 10 24 61 $ 1 62
1993.............................. 23(a) 11 17 10 27 88 3 91
Development
1995.............................. 78(b) 31(c) 6 115 10 125
1994.............................. 55(b) 30 6 91 10 101
1993.............................. 94(b) 44 3 141 15 156
</TABLE>
- ---------------
(a) Includes $1 million for capitalized interest.
(b) Includes $22 million, $19 million and $25 million for capitalized interest
in 1995, 1994 and 1993, respectively.
(c) Includes $1 million for capitalized interest.
54
<PAGE> 57
UNION TEXAS PETROLEUM HOLDINGS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(DOLLARS IN THOUSANDS UNLESS OTHERWISE INDICATED)
The aggregate amount of capitalized costs (including construction in
progress) relating to oil and gas producing activities and the aggregate amount
of the related accumulated depreciation, depletion and amortization ("DD&A")
including accumulated valuation allowances at December 31, were as follows:
<TABLE>
<CAPTION>
CONSOLIDATED SUBSIDIARIES
---------------------------------------------------------
UNITED OTHER NON- TOTAL
STATES UNITED INTER- CONSOLIDATED WORLD-
(ALASKA) KINGDOM INDONESIA PAKISTAN NATIONAL TOTAL INTERESTS WIDE
--------- ------- --------- -------- -------- ------ ------------ ------
(DOLLARS IN MILLIONS)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Proved and unproved properties
Gross capital
1995......................... $26 $1,832 $ 718 $ 79 $ 15 $2,670 $525 $3,195
1994......................... 20 1,437 687 68 13 2,225 512 2,737
1993......................... 19 1,120 658 60 5 1,862 496 2,358
Accumulated DD&A (including
valuation allowances)
1995......................... 13 733 396 48 10 1,200 336 1,536
1994......................... 12 599 361 40 7 1,019 316 1,335
1993......................... 11 479 324 34 5 853 290 1,143
Proved properties
Gross capital
1995......................... 1,822 710 75 4 2,611 525 3,136
1994......................... 1,428 679 63 4 2,174 512 2,686
1993......................... 1,115 648 56 1 1,820 496 2,316
Accumulated DD&A
1995......................... 731 389 46 4 1,170 336 1,506
1994......................... 598 354 39 4 995 316 1,311
1993......................... 478 317 33 1 829 290 1,119
</TABLE>
55
<PAGE> 58
UNION TEXAS PETROLEUM HOLDINGS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(DOLLARS IN THOUSANDS UNLESS OTHERWISE INDICATED)
The results of operations for the Company's oil and gas producing
activities for 1995, 1994 and 1993 were as follows:
<TABLE>
<CAPTION>
CONSOLIDATED SUBSIDIARIES
-----------------------------------------------------------
UNITED OTHER NON- TOTAL
STATES UNITED INTER- CONSOLIDATED WORLD-
(ALASKA) KINGDOM INDONESIA PAKISTAN NATIONAL TOTAL INTERESTS WIDE
-------- ------- --------- -------- -------- ---- ------------ ------
(DOLLARS IN MILLIONS)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
YEAR ENDED DECEMBER 31,
1995
Net sales................ $ 323 $ 276 $ 51 $ 1 $651 $101 $752
Production costs......... 88 55 17 160 12 172
Exploration expenses..... 6 10 8 7 46 77 77
DD&A..................... 138 35 7 180 21 201
Valuation allowances..... 1 4 5 5
---- ----- ----- ---- ---- ---- ---- ----
Total costs and
expenses.............. 6 237 98 31 50 422 33 455
---- ----- ----- ---- ---- ---- ---- ----
(6) 86 178 20 (49) 229 68 297
Income tax expense(a).... 34 105 5 144 47 191
---- ----- ----- ---- ---- ---- ---- ----
Results of
operations(b)......... $ (6) $ 52 $ 73 $ 15 $(49) $ 85 $ 21 $106
==== ===== ===== ==== ==== ==== ==== ====
YEAR ENDED DECEMBER 31,
1994
Net sales................ $ 260 $ 278 $ 39 $ 1 $578 $ 99 $677
----- ----- ---- ---- ---- ---- ----
Production costs......... 83 59 12 154 10 164
Exploration expenses..... 6 9 8 7 24 54 1 55
DD&A..................... 114 37 7 158 25 183
Valuation allowances..... 1 1 2 4 4
Total costs and
expenses.............. 7 207 104 26 26 370 36 406
---- ----- ----- ---- ---- ---- ---- ----
(7) 53 174 13 (25) 208 63 271
Income tax expense(a).... 32 102 4 138 43 181
---- ----- ----- ---- ---- ---- ---- ----
Results of
operations(b)......... $ (7) $ 21 $ 72 $ 9 $(25) $ 70 $ 20 $ 90
==== ===== ===== ==== ==== ==== ==== ====
YEAR ENDED DECEMBER 31,
1993
Net sales................ $ 208 $ 279 $ 49 $ 1 $537 $100 $637
----- ----- ---- ---- ---- ---- ----
Production costs......... 81 62 12 155 9 164
Exploration expenses..... 32 11 16 8 27 94 2 96
DD&A..................... 193 35 6 234 26 260
Valuation allowances..... 2 1 3 3
---- ----- ----- ---- ---- ---- ---- ----
Total costs and
expenses.............. 34 285 114 26 27 486 37 523
---- ----- ----- ---- ---- ---- ---- ----
(34) (77) 165 23 (26) 51 63 114
Income tax expense
(benefit)(a).......... (99) 90 8 (1) 44 43
---- ----- ----- ---- ---- ---- ---- ----
Results of
operations(b)......... $(34) $ 22 $ 75 $ 15 $(26) $ 52 $ 19 $ 71
==== ===== ===== ==== ==== ==== ==== ====
</TABLE>
- ---------------
(a) Computed using statutory rates adjusted for permanent differences, tax
credits and allowances that are reflected in the income tax expense for the
respective years.
(b) Excludes overhead and financing costs.
56
<PAGE> 59
UNION TEXAS PETROLEUM HOLDINGS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(DOLLARS IN THOUSANDS UNLESS OTHERWISE INDICATED)
Standardized measure of discounted future net cash flows -- (Unaudited)
The standardized measure of discounted future net cash flows and changes
therein relating to proved oil and gas reserves for 1995, 1994 and 1993 were as
follows:
<TABLE>
<CAPTION>
CONSOLIDATED SUBSIDIARIES
---------------------------------------- NON- TOTAL
UNITED CONSOLIDATED WORLD-
KINGDOM INDONESIA PAKISTAN TOTAL INTERESTS WIDE
------- --------- -------- ------- ------------ -------
(DOLLARS IN MILLIONS)
<S> <C> <C> <C> <C> <C> <C>
DECEMBER 31, 1995
Future cash inflows.................. $ 3,437 $ 2,861 $232 $ 6,530 $1,260 $ 7,790
Future production and development
costs............................. (1,291) (1,093) (93) (2,477) (507) (2,984)
Future income tax expense............ (656) (867) (36) (1,559) (382) (1,941)
------- ------- ---- ------- ------ -------
Future net cash flows(a)............. 1,490 901 103 2,494 371 2,865
10% discount for estimated timing of
cash flows........................ (661) (403) (30) (1,094) (177) (1,271)
------- ------- ---- ------- ------ -------
Standardized measure of discounted
future net cash flows............. $ 829 $ 498 $ 73 $ 1,400 $ 194 $ 1,594
======= ======= ==== ======= ====== =======
DECEMBER 31, 1994
Future cash inflows.................. $ 2,686 $ 2,622 $180 $ 5,488 $1,155 $ 6,643
Future production and development
costs............................. (1,161) (1,043) (74) (2,278) (492) (2,770)
Future income tax expense............ (487) (781) (24) (1,292) (344) (1,636)
------- ------- ---- ------- ------ -------
Future net cash flows(a)............. 1,038 798 82 1,918 319 2,237
10% discount for estimated timing of
cash flows........................ (466) (365) (22) (853) (161) (1,014)
------- ------- ---- ------- ------ -------
Standardized measure of discounted
future net cash flows............. $ 572 $ 433 $ 60 $ 1,065 $ 158 $ 1,223
======= ======= ==== ======= ====== =======
DECEMBER 31, 1993
Future cash inflows.................. $ 1,920 $ 2,366 $167 $ 4,453 $1,042 $ 5,495
Future production and development
costs............................. (764) (1,089) (80) (1,933) (509) (2,442)
Future income tax expense............ (285) (637) (15) (937) (281) (1,218)
------- ------- ---- ------- ------ -------
Future net cash flows(a)............. 871 640 72 1,583 252 1,835
10% discount for estimated timing of
cash flows........................ (421) (268) (25) (714) (118) (832)
------- ------- ---- ------- ------ -------
Standardized measure of discounted
future net cash flows............. $ 450 $ 372 $ 47 $ 869 $ 134 $ 1,003
======= ======= ==== ======= ====== =======
</TABLE>
- ---------------
(a) Future net cash flows were computed using year-end prices and costs and
statutory tax rates adjusted for permanent differences, tax credits and
allowances.
57
<PAGE> 60
UNION TEXAS PETROLEUM HOLDINGS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(DOLLARS IN THOUSANDS UNLESS OTHERWISE INDICATED)
Changes in the standardized measure of discounted future net cash flows for
the consolidated subsidiaries were as follows:
<TABLE>
<CAPTION>
1995 1994 1993
------ ------ ------
(DOLLARS IN MILLIONS)
<S> <C> <C> <C>
Beginning of year........................................ $1,065 $ 869 $1,016
Sales and transfers of oil and gas produced, net of
production costs....................................... (513) (437) (374)
Net changes in prices, development and production
costs.................................................. 324 358 (767)
Extensions, discoveries and improved recovery, less
related costs.......................................... 20 46 9
Purchase of minerals in place............................ 287 118
Development costs incurred during the period............. 92 73 110
Revisions of previous quantity estimates................. 83 105 384
Increase in present value due to passage of one year..... 185 144 189
Net change in income taxes............................... (143) (211) 302
------ ------ ------
End of year.............................................. $1,400 $1,065 $ 869
====== ====== ======
</TABLE>
The standardized measure data includes estimates of oil and gas reserve
volumes and forecasts of future production rates over the reserve lives.
Estimates of future production expenditures, including taxes and future
development costs, are based on management's best estimate of such costs
assuming a continuation of current economic and operating conditions. No
provision is included for depletion, depreciation and amortization of property
acquisition costs or indirect costs. The sales prices used in the calculation
are the year-end prices of crude oil, including condensate and natural gas
liquids, and natural gas which as of December 31, 1995, were $18.53 per barrel
of U.K. crude oil (Flotta) and $2.85 per Mcf (at the plant inlet) of Indonesian
LNG. Because of the estimated nature of the data presented, changes in price and
cost levels, as well as the timing of future development costs, may have a
significant impact on such data and cause such data not to be representative of
production or cash flows the Company may realize in the future.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
None
58
<PAGE> 61
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
ITEM 11. EXECUTIVE COMPENSATION.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
For the information called for by Items 10, 11, 12 and 13, reference is
made to the Company's definitive proxy statement for its 1996 Annual Meeting of
Stockholders, which will be filed with the Securities and Exchange Commission
within 120 days after December 31, 1995, and portions of which are incorporated
herein by reference.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.
(A) 1 FINANCIAL STATEMENTS.
The following financial statements and the Report of Independent
Accountants are filed as a part of this report on the pages indicated:
Report of Independent Accountants -- page 33.
Consolidated Balance Sheet -- December 31, 1995 and 1994 -- page 34.
Consolidated Statement of Operations -- For the years ended December 31,
1995, 1994 and 1993 -- page 35.
Consolidated Statement of Cash Flows -- For the years ended December 31,
1995, 1994 and 1993 -- page 36.
Consolidated Statement of Stockholders' Equity -- For the years ended
December 31, 1995, 1994 and 1993 -- page 37.
Selected Quarterly Financial Data for the two years ended December 31,
1995 -- page 50.
Selected Financial Data for the five years ended December 31, 1995 -- page
25.
(A) 2 EXHIBITS.
<TABLE>
<CAPTION>
EXHIBIT NO. DESCRIPTION
- --------------------- ------------------------------------------------------------------------
<S> <C>
3.1 Restated Certificate of Incorporation of Union Texas Petroleum Holdings,
Inc., as amended on May 10, 1995 (Filed under the identical exhibit
number to the Company's Form 8-K dated May 18, 1995 (Commission File No.
1-9019) and incorporated herein by reference)
3.2 Bylaws of Union Texas Petroleum Holdings, Inc., as amended (Filed as
Exhibit 3.2 to the Company's Form 10-Q for quarter ended June 30, 1994
(Commission File No. 1-9019) and incorporated herein by reference)
3.3 Specimen of Certificate evidencing the Common Stock (Filed under the
identical exhibit number to the Company's Registration Statement No.
33-16267 and incorporated herein by reference)
4.1 Indenture for 8.25% Senior Notes due November 15, 1999, dated as of
November 15, 1992, between Union Texas Petroleum Holdings, Inc., the
Subsidiaries named therein and State Street Bank and Trust Company
(including form of note) (Filed as Exhibit 10.1 to the Company's Form
10-Q for quarter ended March 31, 1994 (Commission File No. 1-9019) and
incorporated herein by reference)
</TABLE>
59
<PAGE> 62
<TABLE>
<CAPTION>
EXHIBIT NO. DESCRIPTION
- --------------------- ------------------------------------------------------------------------
<S> <C>
4.2 Indenture dated as of March 15, 1995, among Union Texas Petroleum
Holdings, Inc., the Subsidiaries named therein and The First National
Bank of Chicago, as trustee (the "1995 Indenture") (Filed as Exhibit
10.1 to the Company's Form 10-Q for quarter ended March 31, 1995
(Commission File No. 1-9019) and incorporated herein by reference)
4.3 Specimen Form of 8 3/8% Senior Note due March 15, 2005, issued by Union
Texas Petroleum Holdings, Inc. pursuant to the 1995 Indenture (Filed as
Exhibit 10.2 to the Company's Form 10-Q for quarter ended March 31, 1995
(Commission File No. 1-9019) and incorporated herein by reference)
4.4 Specimen Form of 8 1/2% Senior Note due April 15, 2007, issued by Union
Texas Petroleum Holdings, Inc. pursuant to the 1995 Indenture (Filed as
Exhibit 10.3 to the Company's Form 10-Q for quarter ended March 31, 1995
(Commission File No. 1-9019) and incorporated herein by reference)
4.5 Supplement dated November 7, 1995 to Indenture dated as of November 15,
1992 for 8.25% Senior Notes due 1999, between Union Texas Petroleum
Holdings, Inc., the Subsidiaries named therein and State Street Bank and
Trust Company (Filed as Exhibit 4.1 to the Company's Form 8-K dated
November 17, 1995 (Commission File No. 1-9019) and incorporated herein
by reference)
4.6 Supplement dated November 7, 1995 to the 1995 Indenture between Union
Texas Petroleum Holdings, Inc., the Subsidiaries named therein and The
First National Bank of Chicago (Filed as Exhibit 4.2 to the Company's
Form 8-K dated November 17, 1995 (Commission File No. 1-9019) and
incorporated herein by reference)
4.7 Form of Fixed Rate Medium-Term Note issued by the Company pursuant to
the 1995 Indenture (Filed as Exhibit 4.4 to the Company's Registration
Statement No. 33-64049 and incorporated herein by reference). The
Company agrees to furnish to the Commission upon request a copy of each
instrument with respect to issues of such notes of the Company, the
authorized principal amount of which does not exceed 10% of the
consolidated assets of the Company and its subsidiaries.
10.1 Tax Agreement, dated as of June 27, 1985, among Allied Corporation and
Union Texas Petroleum Holdings, Inc. (Filed as Exhibit 10.6 to the
Company's Registration Statement No. 33-00312 and incorporated herein by
reference)
10.2+ Form of Subscription Agreement between Union Texas Petroleum Holdings,
Inc. and certain employees (Filed as Exhibit 10.8 to the Company's
Registration Statement No. 33-00312 and incorporated herein by
reference)
10.3+ Form of Tagalong Agreement between Union Texas Petroleum Holdings, Inc.
and certain employees (Filed as Exhibit 10.9 to the Company's
Registration Statement No. 33-00312 and incorporated herein by
reference)
10.4+ Amended and Restated Union Texas Petroleum Salaried Employees' Pension
Plan, effective as of January 1, 1994 (Filed under the identical exhibit
number to the Company's 1993 Form 10-K (Commission File No. 1-9019) and
incorporated herein by reference)
10.5+ Union Texas Petroleum Holdings, Inc. 1985 Stock Option Plan, as amended
(Filed as Exhibit 10.10 to Post Effective Amendment No. 2 to the
Company's Registration Statement No. 33-12800 and incorporated herein by
reference)
</TABLE>
60
<PAGE> 63
<TABLE>
<CAPTION>
EXHIBIT NO. DESCRIPTION
- --------------------- ------------------------------------------------------------------------
<S> <C>
10.6+ Union Texas Petroleum Holdings, Inc. Executive Severance Plan (Filed as
Exhibit 10.14 to the Company's Registration Statement No. 33-00312 and
incorporated herein by reference) and Appendix A (Filed as Exhibit 10.6
to the Company's 1993 Form 10-K (Commission File No. 1-9019) and
incorporated herein by reference)
10.7+ Amended and Restated Union Texas Petroleum Savings Plan for Salaried
Employees, effective as of January 1, 1993 (Filed under the identical
exhibit number to the Company's 1993 Form 10-K (Commission File No.
1-9019) and incorporated herein by reference)
10.8+ Form of employment letter with A. C. Johnson (Filed as Exhibit 10.16 to
the Company's Registration Statement No. 33-00312 and incorporated
herein by reference)
10.9+ Amended and Restated Supplemental Non-Qualified Savings Plan for
Executive Employees of Union Texas Petroleum Holdings, Inc. and its
Subsidiaries, effective as of January 1, 1993 (Filed under the identical
exhibit number to the Company's 1993 Form 10-K (Commission File No.
1-9019) and incorporated herein by reference)
10.10+ Form of employment letter with executive officers (Filed as Exhibit
10.18 to the Company's Registration Statement No. 33-00312 and
incorporated herein by reference) and Exhibit A (Filed as Exhibit 10.10
to the Company's 1992 Form 10-K (Commission File No. 1-9019) and
incorporated herein by reference)
10.11 Joint Venture Agreement, dated as of August 8, 1968, among Roy M.
Huffington, Inc., Virginia International Company, Austral Petroleum Gas
Corporation, Golden Eagle Indonesia Limited and Union Texas Far East
Corporation, as amended (the "Joint Venture Agreement") (Filed as
Exhibit 6.6 to the Registration Statement No. 2-58834 of Alaska
Interstate Company and incorporated herein by reference)
10.12 Supply Agreement, dated as of April 14, 1981, for Badak LNG Expansion
Project among Perusahaan Pertambangan Minyak Dan Gas Bumi Negara
("Pertamina") and the parties to the Joint Venture Agreement (Filed as
Exhibit 10.14 to the Company's 1992 Form 10-K (Commission File No.
1-9019) and incorporated herein by reference)
10.13 Indenture, dated as of September 25, 1984, between Unimar Company, as
Issuer, and Irving Trust Company, as Trustee, providing for 14,077,747
Indonesian Participating Units (Filed as Exhibit 4 to the Form S-14
Registration Statement No. 2-93037 of Unimar Company and incorporated
herein by reference)
10.14 Amended and Restated Agreement of General Partnership of Unimar Company,
dated as of September 11, 1990 (Filed as Exhibit 3.1 to the Form 10-Q
for quarter ended September 30, 1990 of Unimar Company (Commission File
No. 1-8791) and incorporated herein by reference)
10.15 License No. P054 concerning all or part of the following blocks in the
United Kingdom North Sea: 49/15 and 49/25 (Sean Field) (Filed as Exhibit
10.74 to the Company's Registration Statement No. 33-00312 and
incorporated herein by reference)
10.16 License No. P220 concerning all or part of the following blocks in the
United Kingdom North Sea: 9/26, 14/19, 15/11, 15/15, 15/17 and 210/29
(Piper Field) (Filed as Exhibit 10.75 to the Company's Registration
Statement No. 33-00312 and incorporated herein by reference)
10.17 License No. P249 concerning part of the following block in the United
Kingdom North Sea: 14/19 (Claymore Field) (Filed as Exhibit 10.76 to the
Company's Registration Statement No. 33-00312 and incorporated herein by
reference)
</TABLE>
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10.18 License No. P250 concerning all or part of the following blocks in the
United Kingdom North Sea: 9/26, 15/11, 15/15, 210/29, 15/17 and 14/19
(Scapa Field) (Filed as Exhibit 10.77 to the Company's Registration
Statement No. 33-00312 and incorporated herein by reference)
10.19 Restated United Kingdom Continental Shelf Operating Agreement (Piper
License), dated as of August 11, 1977, among Occidental Petroleum (U.K.)
Limited, Occidental of Britain, Inc., Getty Oil (Britain) Limited,
Allied Chemical (Great Britain) Limited, Allied Chemical (North Sea)
Ltd., Thomson North Sea Limited and the British National Oil Corporation
(Filed as Exhibit No. 10.78 to the Company's Registration Statement No.
33-00312 and incorporated herein by reference)
10.20 Restated United Kingdom Continental Shelf Operating Agreement (Claymore
License), dated August 11, 1977, among Occidental Petroleum (Caledonia)
Limited, Occidental of Scotland, Inc., Getty Oil (Britain) Limited,
Allied Chemical (Great Britain) Limited, Allied Chemical (North Sea)
Ltd., Thomson North Sea Limited and the British National Oil Corporation
(Filed as Exhibit 10.79 to the Company's Registration Statement No.
33-00312 and incorporated herein by reference)
10.21 United Kingdom Continental Shelf Joint Operating Agreement for Blocks
49/15a and 49/25a (Sean Field), dated July 3, 1984, among Shell U.K.
Limited, Union Texas Petroleum Limited, Britoil Public Limited Company
and Esso Exploration and Production U.K. Limited (Filed as Exhibit 10.81
to the Company's Registration Statement No. 33-00312 and incorporated
herein by reference)
10.22 Agreement for Sale and Purchase of Natural Gas from the Sean North and
Sean South Fields, dated November 7, 1984, between Union Texas Petroleum
Limited and British Gas Corporation, including list of omitted schedules
(Filed as Exhibit 10.82 to the Company's Registration Statement No.
33-00312 and incorporated herein by reference)
10.23 Badak III LNG Sales Contract, dated March 19, 1987, between Pertamina,
as Seller, and Chinese Petroleum Corporation, as Buyer (Filed as Exhibit
10.28 to the Company's 1992 Form 10-K (Commission File No. 1- 9019) and
incorporated herein by reference)
10.24 Supplemental Indenture, dated as of October 31, 1986, to the Indenture
between Unimar Company and Irving Trust Company (Exhibit 10.13 above)
(Filed as Exhibit 10.114 to the Company's Registration Statement No.
33-16267 and incorporated herein by reference)
10.25 Amended and Restated Registration Rights Agreement, dated September 30,
1987, among Union Texas Petroleum Holdings, Inc. and Certain Holders of
Certain Securities of Union Texas Petroleum Holdings, Inc. (Filed as
Exhibit 10.117 to Post Effective Amendment No. 1 to the Company's
Registration Statement No. 33-12800 and incorporated herein by
reference)
10.26+ Union Texas Petroleum Holdings, Inc. 1987 Stock Option Plan and First
Amendment to Union Texas Petroleum Holdings, Inc. 1987 Stock Option Plan
(Filed as Exhibit 4.4 to the Company's Registration Statement No.
33-21684 and incorporated herein by reference)
</TABLE>
62
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<CAPTION>
EXHIBIT NO. DESCRIPTION
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<S> <C>
10.27 Bontang Capital Projects Loan Agreement No. 2, dated as of June 9, 1987,
among Continental Bank International, as Trustee under the Badak Trustee
and Paying Agent Agreement (Borrower), the banks named therein as Lead
Managers and Lenders and The Industrial Bank of Japan Trust Company
(Agent) (Filed as Exhibit 10.125 to the Company's Registration Statement
No. 33-16267 and incorporated herein by reference)
10.28 Producers Agreement No. 2, dated as of June 9, 1987, by Pertamina, Roy
M. Huffington, Inc., Virginia International Company, Ultramar Indonesia
Limited, Virginia Indonesia Company ("VICO"), Union Texas East
Kalimantan Limited, Universe Tankships, Inc. and Huffington Corporation
in favor of The Industrial Bank of Japan Trust Company as Agent (Filed
as Exhibit 10.126 to the Company's Registration Statement No. 33-16267
and incorporated herein by reference)
10.29 Badak III LNG Sales Contract Supply Agreement, dated October 19, 1987,
among Pertamina and the parties to the Joint Venture Agreement (Filed as
Exhibit 10.132 to Post Effective Amendment No. 1 to the Company's
Registration Statement No. 33-12800 and incorporated herein by
reference)
10.30 $316,000,000 Bontang III Loan Agreement, dated February 9, 1988, among
the Trustee under the Bontang III Trustee and Paying Agent Agreement,
Train-E Finance Co., Ltd., as Tranche A Lender and The Industrial Bank
of Japan Trust Company as Agent for the Tranche B Lenders and as Tranche
B Lender (Filed as Exhibit 10.83 to Post Effective Amendment No. 2 to
the Company's Registration Statement No. 33-12800 and incorporated
herein by reference)
10.31 Bontang III Producers Agreement, dated as of February 9, 1988, among
Pertamina, Roy M. Huffington, Inc., Huffington Corporation, VICO,
Virginia International Company, Ultramar Indonesia Company Limited,
Union Texas East Kalimantan Limited, Universe Tankships, Inc., Total
Indonesie, Unocal Indonesia, Ltd., Indonesia Petroleum, Ltd., in favor
of Train-E Finance Co., Ltd., as Tranche A Lender, The Industrial Bank
of Japan Trust Company as Agent for the Tranche B Lenders and as Tranche
B Lender, and the other Tranche B Lenders named therein (Filed as
Exhibit 10.84 to the Post Effective Amendment No. 2 to the Company's
Registration Statement No. 33-12800 and incorporated herein by
reference)
10.32 Bontang III Trustee and Paying Agent Agreement, dated February 9, 1988,
among Pertamina, Roy M. Huffington, Inc., Huffington Corporation,
Virginia International Company, VICO, Ultramar Indonesia Limited, Union
Texas East Kalimantan Limited, Universe Tankships, Inc., Total
Indonesie, Unocal Indonesia, Ltd., Indonesia Petroleum, Ltd. and the
Trustee thereunder (Filed as Exhibit 10.42 to the Company's 1991 Form
10-K (Commission File No. 1-9019) and incorporated herein by reference)
10.33 $21,250,000 Financing Agreement, dated December 20, 1988, among Union
Texas Pakistan, Inc. and Overseas Private Investment Corporation (Filed
as Exhibit 10.85 to the Company's 1988 Form 10-K (Commission File No.
1-9019) and incorporated herein by reference)
10.34 Guaranty Agreement, dated December 20, 1988, between Union Texas
Petroleum Holdings, Inc. and Overseas Private Investment Corporation
(Filed as Exhibit 10.86 to the Company's 1988 Form 10-K (Commission File
No. 1-9019) and incorporated herein by reference)
10.35+ First Amendment to Union Texas Petroleum Holdings, Inc. Executive
Severance Plan (Filed as Exhibit 10.87 to the Company's 1989 Form 10-K
(Commission File No. 1-9019) and incorporated herein by reference)
</TABLE>
63
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<S> <C>
10.36+ Second Amendment to Union Texas Petroleum Holdings, Inc. Executive
Severance Plan (Filed as Exhibit 10.88 to the Company's 1989 Form 10-K
(Commission File No. 1-9019) and incorporated herein by reference)
10.37+ Third Amendment to Union Texas Petroleum Holdings, Inc. Executive
Severance Plan (Filed as Exhibit 10.93 to the Company's Form 10-Q for
quarter ended June 30, 1990 (Commission File No. 1-9019) and
incorporated herein by reference)
10.38+ Third Amendment to Union Texas Petroleum Holdings, Inc. 1985 Stock
Option Plan (Filed as Exhibit 10.95 to the Company's Form 10-Q for
quarter ended June 30, 1990 (Commission File No. 1-9019) and
incorporated herein by reference)
10.39+ Second Amendment to Union Texas Petroleum Holdings, Inc. 1987 Stock
Option Plan (Filed as Exhibit 10.96 to the Company's Form 10-Q for
quarter ended June 30, 1990 (Commission File No. 1-9019) and
incorporated herein by reference)
10.40+ Union Texas Petroleum Supplemental Retirement Plan (Filed as Exhibit
10.99 to the Company's Form 10-Q for quarter ended June 30, 1990
(Commission File No. 1-9019) and incorporated herein by reference)
10.41+ Amended and Restated Union Texas Petroleum Supplemental Retirement Plan
II, effective January 1, 1994 (Filed under the identical exhibit number
to the Company's 1993 Form 10-K (Commission File No. 1-9019) and
incorporated herein by reference)
10.42+ Union Texas Petroleum Supplemental Retirement Plans Trust, as amended
(Filed as Exhibit 10.101 to the Company's Form 10-Q for quarter ended
June 30, 1990 (Commission File No. 1-9019) and incorporated herein by
reference)
10.43 Amended and Restated Production Sharing Contract effective August 8,
1968-August 7, 1998 among Pertamina, Roy M. Huffington, Inc., VICO,
Virginia International Company, Ultramar Indonesia Limited, Union Texas
East Kalimantan Limited, Universe Gas & Oil Company, Inc. and Huffington
Corporation (Filed as Exhibit 10.102 to the Company's Form 10-Q for
quarter ended June 30, 1990 (Commission File No. 1-9019) and
incorporated herein by reference)
10.44 Production Sharing Contract effective August 8, 1998-August 7, 2018
among Pertamina, Roy M. Huffington, Inc., VICO, Virginia International
Company, Ultramar Indonesia Limited, Union Texas East Kalimantan
Limited, Universe Gas & Oil Company, Inc. and Huffington Corporation
(Filed as Exhibit 10.103 to the Company's Form 10-Q for quarter ended
June 30, 1990 (Commission File No. 1-9019) and incorporated herein by
reference)
10.45 Joint Operating Agreement for the Scapa Field, dated December 23, 1985,
among Occidental Petroleum (Caledonia) Limited, Texaco Britain Limited,
Union Texas Petroleum Limited, Thomson North Sea Limited, Thomson
Scottish Petroleum Limited and the Oil and Pipelines Agency (Filed as
Exhibit 10.104 to the Company's Form 10-Q for quarter ended June 30,
1990 (Commission File No. 1-9019) and incorporated herein by reference)
10.46 Amended and Restated 1973 LNG Sales Contract, dated as of the 1st day of
January, 1990, by and between Pertamina, as Seller, and Chubu Electric
Power Co., Inc., The Kansai Electric Power Co., Inc., Kyushu Electric
Power Co., Inc., Nippon Steel Corporation, Osaka Gas Co., Ltd. and Toho
Gas Co., Ltd., as Buyers (Filed as Exhibit (10)-8 to the 1993 Form 10-K
of Unimar Company (Commission File No. 1-8791) and incorporated herein
by reference)
</TABLE>
64
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EXHIBIT NO. DESCRIPTION
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<S> <C>
10.47 Amended and Restated Badak LNG Sales Contract, dated as of the 1st day
of January, 1990, by and between Pertamina, as Seller, and Chubu
Electric Power Co., Inc., The Kansai Electric Power Co., Inc., Osaka Gas
Co., Ltd. and Toho Gas Co., Ltd., as Buyers (Filed as Exhibit (10)-11 to
the 1993 Form 10-K of Unimar Company (Commission File No. 1-8791) and
incorporated herein by reference)
10.48+ Fourth Amendment to Union Texas Petroleum Holdings, Inc. Executive
Severance Plan (Filed as Exhibit 10.85 to the Company's 1990 Form 10-K
(Commission File No. 1-9019) and incorporated herein by reference)
10.49 Asset Purchase Agreement, dated March 12, 1991, among Union Texas
Petroleum Holdings, Inc., Union Texas Petroleum Corporation, Union Texas
Development Corporation, Union Texas Exploration Corporation, Benoil,
Inc. and NERCO Oil & Gas, Inc. (Filed as Exhibit 2.1 to the Company's
Form 8-K dated April 19, 1991 (Commission File No. 1-9019) and
incorporated herein by reference)
10.50 Asset Purchase Agreement, dated August 20, 1991, among Union Texas
Petroleum Corporation, Union Texas Canada Ltd., Union Texas Development
Corporation, Meridian Oil Production Inc. and El Paso Production Company
(Filed as Exhibit 2.1 to the Company's Form 8-K dated October 1, 1991
(Commission File No. 1-9019) and incorporated herein by reference)
10.51+ Fifth Amendment to Union Texas Petroleum Holdings, Inc. Executive
Severance Plan (Filed as Exhibit 10.69 to the Company's 1991 Form 10-K
(Commission File No. 1-9019) and incorporated herein by reference)
10.52 Asset Purchase Agreement, dated September 17, 1991, among Union Texas
Petroleum Holdings, Inc., Union Texas Products Corporation and Western
Gas Resources, Inc. (Filed as Exhibit 2.1 to the Company's Form 8-K
dated November 14, 1991 (Commission File No. 1-9019) and incorporated
herein by reference)
10.53 Amended and Restated Bontang Processing Agreement, dated February 9,
1988, among Pertamina and Roy M. Huffington, Inc., Huffington
Corporation, VICO, Virginia International Company, Ultramar Indonesia
Limited, Union Texas East Kalimantan Limited, Universe Tankships, Inc.,
Total Indonesie, Unocal Indonesia, Ltd., Indonesia Petroleum, Ltd. and
P.T. Badak Natural Gas Liquefaction Company (Filed as Exhibit (10)-39 to
the 1988 Form 10-K of Unimar Company (Commission File No. 1-8791) and
incorporated herein by reference)
10.54 Amended and Restated Debt Service Allocation Agreement, dated February
9, 1988, among Pertamina and Roy M. Huffington, Inc., VICO, Ultramar
Indonesia Limited, Virginia International Company, Union Texas East
Kalimantan Limited, Universe Tankships, Inc., Huffington Corporation,
Total Indonesie, Unocal Indonesia, Ltd. and Indonesia Petroleum, Ltd.
(Filed as Exhibit (10)-40 to the 1988 Form 10-K of Unimar Company
(Commission File No. 1-8791) and incorporated herein by reference)
10.55 Amendment No. 1 to Bontang III Producers Agreement, dated as of May 31,
1988, among Pertamina, Roy M. Huffington, Inc., Huffington Corporation,
VICO, Virginia International Company, Ultramar Indonesia Company
limited, Union Texas East Kalimantan Limited, Universe Tankships, Inc.,
Total Indonesie, Unocal Indonesia, Ltd., Indonesia Petroleum, Ltd. and
Train-E Finance Co., Ltd., as Tranche A Lender, and The Industrial Bank
of Japan Trust Company on behalf of the Tranche B Lender, (Filed as
Exhibit (10)-21 to the 1993 Form 10-K of Unimar Company (Commission File
No. 1-8791) and incorporated herein by reference)
</TABLE>
65
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- --------------------- ------------------------------------------------------------------------
<S> <C>
10.56 Amendment No. 2 to Producers Agreement No. 2, dated as of May 31, 1988,
among Pertamina, Roy M. Huffington, Inc., Huffington Corporation, VICO,
Virginia International Company, Ultramar Indonesia Company Limited,
Union Texas East Kalimantan Limited and Universe Tankships, Inc. (Filed
as Exhibit (10)-44 to the 1988 Form 10-K of Unimar Company (Commission
File No. 1-8791) and incorporated herein by reference)
10.57 Badak IV LNG Sales Contract, dated October 23, 1990, between Pertamina,
as Seller, and Osaka Gas Co., Ltd., Tokyo Gas Co., Ltd. and Toho Gas
Co., Ltd., as Buyer (Filed as Exhibit (10)-65 to the 1990 Form 10-K of
Unimar Company (Commission File No. 1-8791) and incorporated herein by
reference)
10.58 Supply Agreement for Natural Gas to Badak IV LNG Sales Contract, dated
August 12, 1991, by and between Pertamina, VICO, Opicoil Houston, Inc.,
Ultramar Indonesia Limited, Union Texas East Kalimantan Limited,
Universe Gas & Oil Company, Inc. and Virginia International Company
(Filed as Exhibit 10.80 to the Company's 1991 Form 10-K (Commission File
No. 1-9019) and incorporated herein by reference)
10.59 LNG Sales and Purchase Contract (Korea II), dated May 7, 1991, between
Pertamina, as Seller, and Korea Gas Corporation, as Buyer (Filed as
Exhibit (10)-1 to the 1990 Form 10-Q for quarter ended June 30, 1991 of
Unimar Company (Commission File No. 1-8791) and incorporated herein by
reference)
10.60 Amended and Restated Bontang II Trustee and Paying Agent Agreement,
dated as of July 15, 1991, among Pertamina, VICO, Opicoil Houston, Inc.,
Virginia International Company, Ultramar Indonesia Limited, Union Texas
East Kalimantan Limited, Universe Gas & Oil Company, Inc., Total
Indonesie, Unocal Indonesia, Ltd., Indonesia Petroleum, Ltd. and the
Trustee thereunder (Filed as Exhibit 10.82 to the Company's 1991 Form
10-K (Commission File No. 1-9019) and incorporated herein by reference)
10.61 $750,000,000 Bontang IV Loan Agreement, dated as of August 26, 1991,
among the Trustee under the Bontang IV Trustee and Paying Agent
Agreement as Borrower, Chase Manhattan Asia Limited and The Mitsubishi
Bank, Limited as Coordinators, the other banks and financial
institutions named therein as Arrangers, Co-Arrangers, Lead Managers,
Managers, Co-Managers and Lenders, The Chase Manhattan Bank, N.A. and
The Mitsubishi Bank, Limited as Co-Agents and The Chase Manhattan Bank,
N.A. as Agent (Filed as Exhibit 10.1 to the Form 10-Q for quarter ended
September 30, 1991 of Unimar Company (Commission File No. 1-8791) and
incorporated herein by reference)
10.62 Bontang IV Producers Agreement, dated as of August 26, 1991, by
Pertamina, Virginia International Company, Opicoil Houston, Inc., VICO,
Ultramar Indonesia Limited, Union Texas East Kalimantan Limited,
Universe Gas & Oil Company, Inc., Total Indonesie, Unocal Indonesia,
Ltd. and Indonesia Petroleum, Ltd. in favor of The Chase Manhattan Bank,
N.A., as Agent for the Lenders and as Lender, and the other Lenders
named therein (Filed as Exhibit 10.2 to the Form 10-Q for quarter ended
September 30, 1991 of Unimar Company (Commission File No. 1-8791) and
incorporated herein by reference)
</TABLE>
66
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<CAPTION>
EXHIBIT NO. DESCRIPTION
- --------------------- ------------------------------------------------------------------------
<S> <C>
10.63 Bontang IV Trustee and Paying Agent Agreement, dated as of August 26,
1991, among Pertamina, Virginia International Company, Opicoil Houston,
Inc., VICO, Ultramar Indonesia Limited, Union Texas East Kalimantan
Limited, Universe Gas & Oil Company, Inc., Total Indonesie, Unocal
Indonesia, Ltd., Indonesia Petroleum, Ltd. and the Trustee thereunder
(Filed as Exhibit 10.3 to the Form 10-Q for quarter ended September 30,
1991 of Unimar Company (Commission File No. 1-8791) and incorporated
herein by reference)
10.64+ Sixth Amendment to Union Texas Petroleum Holdings, Inc. Executive
Severance Plan (Filed as Exhibit 10.77 to the Company's 1992 Form 10-K
(Commission File No. 1-9019) and incorporated herein by reference)
10.65 Consulting Agreement, dated as of November 18, 1992, among Petroleum
Associates, L.P., KKR Partners II, L.P. and Union Texas Petroleum
Holdings, Inc. (Filed as Exhibit 10.81 to the Company's 1992 Form 10-K
(Commission File No. 1-9019) and incorporated herein by reference)
10.66+ Second Amendment to Union Texas Petroleum Supplemental Retirement Plans
Trust (Filed as Exhibit 10.82 to the Company's 1992 Form 10-K
(Commission File No. 1-9019) and incorporated herein by reference)
10.67 Amendment No. 1 to Bontang III Trustee and Paying Agent Agreement, dated
as of December 11, 1992, among Pertamina, VICO, Virginia International
Company, Ultramar Indonesia Limited, Union Texas East Kalimantan
Limited, Opicoil Houston, Inc., Universe Gas & Oil Company, Inc., Total
Indonesie, Unocal Indonesia Ltd., Indonesia Petroleum, Ltd. and the
Bontang III Trustee (Filed as Exhibit 10.83 to the Company's 1992 Form
10-K (Commission File No. 1-9019) and incorporated herein by reference)
10.68+ Key Employee Incentive Compensation Plan (Filed as Exhibit 10.84 to the
Company's 1992 Form 10-K (Commission File No. 1-9019) and incorporated
herein by reference)
10.69+ First Amendment to Union Texas Petroleum Supplemental Retirement Plan
(Filed as Exhibit 10.85 to the Company's 1992 Form 10-K (Commission File
No. 1-9019) and incorporated herein by reference)
10.70+ Union Texas Petroleum Holdings, Inc. 1992 Stock Option Plan (Filed as
Exhibit 4.3 to the Company's Registration Statement No. 33-64928 and
incorporated herein by reference)
10.71 Arun and Bontang LPG Sales and Purchase Contract, dated July 15, 1986,
between Pertamina, as Seller, and Mitsubishi Corporation, Cosmo Oil Co.,
Ltd., Nippon Petroleum Gas Co., Ltd., Showa Shell Sekiyu K.K., Kyodo Oil
Co., Ltd., Idemitsu Kosan Co., Ltd. and Mitsui Liquefied Gas Co., Ltd.,
as Buyers (Filed as Exhibit (10)-60 to the 1991 Form 10-K of Unimar
Company (Commission File No. 1-8791) and incorporated herein by
reference)
10.72 Petroleum Concession Agreement, dated January 21, 1992, between the
President of the Islamic Republic of Pakistan and Union Texas Pakistan,
Inc., Occidental Petroleum (Pakistan) Inc. and Oil & Development
Corporation (Filed as Exhibit 10.87 to the Company's Form 10-Q for
quarter ended March 31, 1992 (Commission File No. 1-9019) and
incorporated herein by reference)
</TABLE>
67
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EXHIBIT NO. DESCRIPTION
- --------------------- ------------------------------------------------------------------------
<S> <C>
10.73 Amended and Restated Supply Agreement (In support of the Amended and
Restated 1973 LNG Sales Contract), dated September 22, 1993, and
effective December 3, 1973, between Pertamina and VICO, LASMO Sanga
Sanga Limited, Opicoil Houston, Inc., Union Texas East Kalimantan
Limited, Universe Gas & Oil Company, Inc. and Virginia International
Company (Filed as Exhibit 10.75 to the Company's 1993 Form 10-K
(Commission File No. 1-9019) and incorporated herein by reference)
10.74 Amended and Restated Credit Agreement dated as of May 13, 1994, among
Union Texas Petroleum Holdings, Inc., the Banks listed therein and
NationsBank of Texas, N.A., as agent, and Bank of America National Trust
and Savings Association and Union Bank of Switzerland, Houston Agency,
as co-agents, with form of note attached (the "Amended and Restated
Credit Agreement") (Filed as Exhibit 10.1 to the Company's Registration
Statement No. 33-52683 and incorporated herein by reference)
10.75 First Amendment Agreement dated as of November 21, 1994, to the Amended
and Restated Credit Agreement, among Union Texas Petroleum Holdings,
Inc., the Banks and Co-Agents listed therein and NationsBank of Texas,
N.A., as agent (Filed as Exhibit 10.75 to the Company's 1994 Form 10-K
(Commission File No. 1-9019) and incorporated herein by reference)
10.76 Second Amendment Agreement dated as of January 31, 1995, to the Amended
and Restated Credit Agreement, as amended, among Union Texas Petroleum
Holdings, Inc., the Banks and Co-Agents listed therein and NationsBank
of Texas, N.A., as agent (Filed as Exhibit 10.76 to the Company's 1994
Form 10-K (Commission File No. 1-9019) and incorporated herein by
reference)
10.77+ Seventh Amendment to Union Texas Petroleum Holdings, Inc. Executive
Severance Plan (Filed as Exhibit 10.5 to the Company's Form 10-Q for
quarter ended June 30, 1994 (Commission File No. 1-9019) and
incorporated herein by reference)
10.78 East Sean Gas Sales Agreement, dated August 30, 1994, between Union
Texas Petroleum Limited and Alliance Gas Limited (Filed as Exhibit 10.3
to the Company's Form 10-Q for quarter ended September 30, 1994
(Commission File No. 1-9019) and incorporated herein by reference)
10.79 Share Sale Agreement, dated October 18, 1994, among Union Texas
Petroleum Limited, Fina Petroleum Development Limited and Fina
Exploration Limited (the "Share Sale Agreement") (Filed as Exhibit 2.1
to the Company's Form 8-K dated November 14, 1994 (Commission File No.
1-9019) and incorporated herein by reference)
10.80 Guarantee, dated October 18, 1994, by Union Texas International
Corporation relating to the Share Sale Agreement (Filed as Exhibit 2.3
to the Company's Form 8-K dated November 14, 1994 (Commission File No.
1-9019) and incorporated herein by reference)
10.81 Petroleum Concession Agreement, dated April 20, 1977, between the
President of Pakistan and Union Texas Pakistan, Inc. (Filed as Exhibit
10.87 to the Company's 1994 Form 10-K (Commission File No. 1-9019) and
incorporated herein by reference)
</TABLE>
68
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<TABLE>
<CAPTION>
EXHIBIT NO. DESCRIPTION
- --------------------- ------------------------------------------------------------------------
<S> <C>
10.82 Amendments to Arun and Bontang LPG Sales and Purchase Contract, dated
October 5, 1994, between Pertamina, as Seller, and Mitsubishi
Corporation, Cosmo Oil Co., Ltd., Nippon Petroleum Gas Co., Ltd., Showa
Shell Sekiyu K.K., Japan Energy Corporation, Idemitsu Kosan Co., Ltd.
and Mitsui Oil & Gas Co., Ltd., as Buyers (Filed as Exhibit 10.88 to the
Company's 1994 Form 10-K (Commission File No. 1-9019) and incorporated
herein by reference)
10.83 Amendment to the Amended and Restated 1973 LNG Sales Contract, dated as
of the 1st day of June 1992, by and between Pertamina, as Seller, and
Kyushu Electric Power Co., Inc., Nippon Steel Corporation and Toho Gas
Co., Ltd., as Buyers (Filed as Exhibit (10)-9 to the 1993 Form 10-K of
Unimar Company (Commission File No. 1-8791) and incorporated herein by
reference)
10.84 Third Amendment Agreement, dated as of April 24, 1995, to the Amended
and Restated Credit Agreement, as amended, among Union Texas Petroleum
Holdings, Inc., the Banks and Co-Agents listed therein and NationsBank
of Texas, N.A., as Agent (Filed as Exhibit 10.1 to the Company's Form
10-Q for quarter ended June 30, 1995 (Commission File No. 1-9019) and
incorporated herein by reference)
10.85 $100,000,000 Credit Agreement dated as of April 24, 1995, among Union
Texas Petroleum Holdings, Inc., the Banks and Co-Agents listed therein
and NationsBank of Texas, N.A., as Agent (Filed as Exhibit 10.3 to the
Company's Form 10-Q for quarter ended June 30, 1995 (Commission File No.
1-9019) and incorporated herein by reference)
10.86 Fourth Amendment Agreement, dated as of June 16, 1995, to the Amended
and Restated Credit Agreement, as amended, among Union Texas Petroleum
Holdings, Inc., the Banks and Co-Agents listed therein and NationsBank
of Texas, N.A., as Agent (Filed as Exhibit 10.5 to the Company's Form
10-Q for quarter ended June 30, 1995 (Commission File No. 1-9019) and
incorporated herein by reference)
10.87 First Amendment Agreement, dated as of June 16, 1995, to the Credit
Agreement dated as of April 24, 1995, among Union Texas Petroleum
Holdings, Inc., the Banks and Co-Agents listed therein and NationsBank
of Texas, N.A., as Agent (Filed as Exhibit 10.6 to the Company's Form
10-Q for quarter ended June 30, 1995 (Commission File No. 1-9019) and
incorporated herein by reference)
10.88 Facility Agreement, dated May 26, 1995, among Union Texas Britannia
Limited, Chemical Bank, as Arranger, NationsBank, N.A. Carolinas, as
Facility Agent, National Westminster Bank plc, as Funding Agent, and the
Co-Arrangers, Technical Agents, Account Bank and Banks named therein
(Filed as Exhibit 10.9 to the Company's Form 10-Q for quarter ended June
30, 1995 (Commission File No. 1-9019) and incorporated herein by
reference)
10.89 Sponsor Direct Agreement, dated May 26, 1995, among Union Texas
Petroleum Limited, Union Texas Britannia Limited and NationsBank N.A.
Carolinas, as Facility Agent (Filed as Exhibit 10.10 to the Company's
Form 10-Q for quarter ended June 30, 1995 (Commission File No. 1-9019)
and incorporated herein by reference)
10.90 Sponsor Support Agreement, dated May 26, 1995, between Union Texas
Petroleum Limited and Union Texas Britannia Limited (Filed as Exhibit
10.11 to the Company's Form 10-Q for quarter ended June 30, 1995
(Commission File No. 1-9019) and incorporated herein by reference)
10.91+ Union Texas Petroleum Holdings, Inc. 1994 Incentive Plan (Filed as
Exhibit 10.12 to the Company's Form 10-Q for quarter ended June 30, 1995
(Commission File No. 1-9019) and incorporated herein by reference)
</TABLE>
69
<PAGE> 72
<TABLE>
<CAPTION>
EXHIBIT NO. DESCRIPTION
- --------------------- ------------------------------------------------------------------------
<S> <C>
10.92+ First Amendment to Union Texas Petroleum Holdings, Inc. 1992 Stock
Option Plan (Filed as Exhibit 10.13 to the Company's Form 10-Q for
quarter ended June 30, 1995 (Commission File No. 1-9019) and
incorporated herein by reference)
10.93 Sale and Purchase Agreement dated May 31, 1995, between Union Texas
Petroleum Limited and Oryx U.K. Energy Company (Filed as Exhibit 10.14
to the Company's Form 10-Q for quarter ended June 30, 1995 (Commission
File No. 1-9019) and incorporated herein by reference)
10.94 Bontang V Loan Agreement, dated as of July 1, 1995, among BankAmerica
International, as Trustee under the Bontang V Trustee and Paying Agent
Agreement, as Borrower, Bontang Train-G Project Finance Co., Ltd.
("Tranche A Lender"), the Banks named therein as Tranche B Lenders, The
Long-Term Credit Bank of Japan, Limited, New York Branch ("Facility
Agent"), The Fuji Bank, Limited ("Intercreditor Agent"), Credit Lyonnais
("Technical Agent"), and Credit Lyonnais, The Fuji Bank, Limited and The
Long-Term Credit Bank of Japan, Limited (collectively, the "Arrangers")
(Filed as Exhibit 10.1 to the Company's Form 10-Q for quarter ended
September 30, 1995 (Commission File No. 1-9019) and incorporated herein
by reference)
10.95 Bontang V Producers Agreement, dated as of July 1, 1995, by Pertamina,
VICO, OPICOIL Houston, Inc., Virginia International Company, LASMO Sanga
Sanga Limited, Union Texas East Kalimantan Limited, Universe Gas & Oil
Company, Inc., Total Indonesie, Unocal Indonesia Company and Indonesia
Petroleum, Ltd. (collectively, the "Producers"), in favor of the Tranche
A Lender, the Banks named therein as Tranche B Lenders and the Facility
Agent, Intercreditor Agent and Technical Agent (Filed as Exhibit 10.2 to
the Company's Form 10-Q for quarter ended September 30, 1995 (Commission
File No. 1-9019) and incorporated herein by reference)
10.96 Bontang V Trustee and Paying Agent Agreement, dated as of July 1, 1995,
among the Producers and BankAmerica International, as Trustee and Paying
Agent (Filed as Exhibit 10.3 to the Company's Form 10-Q for quarter
ended September 30, 1995 (Commission File No. 1-9019) and incorporated
herein by reference)
10.97 Amendment No. 1 to Bontang III Loan Agreement, dated as of July 1, 1995,
among Continental Bank International, as Trustee under the Bontang III
Trustee and Paying Agent Agreement, Train-E Finance Co., Ltd., as
Tranche A Lender, and The Industrial Bank of Japan Trust Company, as
Agent on behalf of the Majority Tranche B Lenders (Filed as Exhibit 10.6
to the Company's Form 10-Q for quarter ended September 30, 1995
(Commission File No. 1-9019) and incorporated herein by reference)
10.98 Second Amended and Restated 1973 LNG Sales Contract, dated as of August
3, 1995, between Pertamina, as Seller, and Chubu Electric Power Co.,
Inc., The Kansai Electric Power Co., Inc., Kyushu Electric Power Co.,
Inc., Nippon Steel Corporation, Osaka Gas Co., Ltd. and Toho Gas Co.,
Ltd., as the Buyers, with related letter agreement, dated August 3,
1995, between Seller and Buyers (Filed as Exhibit 10.7 to the Company's
Form 10-Q for quarter ended September 30, 1995 (Commission File No.
1-9019) and incorporated herein by reference)
</TABLE>
70
<PAGE> 73
<TABLE>
<CAPTION>
EXHIBIT NO. DESCRIPTION
- --------------------- ------------------------------------------------------------------------
<S> <C>
10.99 Package V Supply Agreement for Natural Gas in Support of the 1973 LNG
Sales Contract Extension, dated June 16, 1995, effective October 6,
1994, between Pertamina and VICO, LASMO Sanga Sanga Limited, OPICOIL
Houston, Inc., Union Texas East Kalimantan Limited, Universe Gas and Oil
Company, Inc. and Virginia International Company (Filed as Exhibit 10.8
to the Company's Form 10-Q for quarter ended September 30, 1995
(Commission File No. 1-9019) and incorporated herein by reference)
10.100+ First Amendment to Union Texas Petroleum Savings Plan for Salaried
Employees (Filed as Exhibit 10.9 to the Company's Form 10-Q for quarter
ended September 30, 1995 (Commission File No. 1-9019) and incorporated
herein by reference)
10.101 Fifth Amendment Agreement dated as of November 3, 1995, to the Amended
and Restated Credit Agreement, as amended, among Union Texas Petroleum
Holdings, Inc., the Banks and Co-Agents listed therein, and NationsBank
of Texas, N.A., as Agent (Filed as Exhibit 10.1 to the Company's Form
8-K dated November 17, 1995 (Commission File No. 1-9019) and
incorporated herein by reference)
10.102 Second Amendment Agreement dated as of November 3, 1995, to the Credit
Agreement dated as of April 24, 1995, as amended, among Union Texas
Petroleum Holdings, Inc., the Banks and Co-Agents listed therein, and
NationsBank of Texas, N.A., as Agent (Filed as Exhibit 10.2 to the
Company's Form 8-K dated November 17, 1995 (Commission File No. 1-9019)
and incorporated herein by reference)
10.103+# Second Amendment to Union Texas Petroleum Savings Plan for Salaried
Employees
10.104# Second Amended and Restated 1981 Badak LNG Sales Contract, dated as of
August 3, 1995, between Pertamina, as Seller, and Chubu Electric Power
Co., Inc., The Kansai Electric Power Co., Inc., Osaka Gas Co., Ltd. and
Toho Gas Co., Ltd., as Buyers, with related letter agreement, dated
August 3, 1995, between Seller and Buyers
10.105# LNG Sales and Purchase Contract (Badak V), dated August 12, 1995,
between Pertamina and Korea Gas Corporation
10.106# LNG Sale and Purchase Contract (Badak VI), dated October 25, 1995,
between Pertamina and Chinese Petroleum Corporation
10.107# Badin-II Revised Petroleum Concession Agreement
21.1# List of Subsidiaries
23.1 Consent of Price Waterhouse LLP is included on page S-1 of this Annual
Report on Form 10-K
24.1 Power of Attorney, pursuant to which amendments to this Annual Report on
Form 10-K may be filed, is included on page 73 of this Annual Report on
Form 10-K
27.1# Financial data schedule
</TABLE>
- ---------------
+ Executive Severance Plan or Arrangement pursuant to Item 601(b)(10)(iii)(A) of
Regulation S-K.
# Filed herewith.
71
<PAGE> 74
(B) REPORTS ON FORM 8-K.
The Company filed Current Reports on Form 8-K dated: (i) November 17, 1995,
to attach press releases announcing the Company's 1995 third quarter results and
the Company's estimates of its year-end reserves, to report the discharge and
release of certain of the Company's subsidiaries from their guarantee
obligations under the Company's three unsecured credit facilities and its
outstanding 8.25% Senior Notes, 8 3/8% Senior Notes and 8 1/2% Notes and to
report the Company's shelf registration of up to $100 million aggregate
principal amount of debt securities and issuance of $30 million of medium-term
notes ("MTNs") thereunder; (ii) December 6, 1995, to report that the Company had
completed its MTN program; (iii) December 18, 1995, to attach a press release
announcing the election of John L. Whitmire as Chairman and Chief Executive
Officer of the Company effective January 9, 1996; (iv) January 30, 1996, to
attach press releases announcing the 1995 year-end and fourth quarter results
and the 1996 capital spending budget; and (v) February 21, 1996, to attach a
press release reporting discoveries in Pakistan. The Company also filed a Form
8-K/A dated October 2, 1995 to include certain historical and proforma
information for the Alba acquisition.
72
<PAGE> 75
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON
ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED.
UNION TEXAS PETROLEUM HOLDINGS, INC.
Date: March 13, 1996 By: /s/ DONALD M. MCMULLAN
------------------------------------
DONALD M. MCMULLAN
VICE PRESIDENT AND CONTROLLER
POWER OF ATTORNEY
We, the undersigned, directors and officers of Union Texas Petroleum
Holdings, Inc. (the "Company"), do hereby severally constitute and appoint John
L. Whitmire, Larry D. Kalmbach and Donald M. McMullan and each or any one of
them, our true and lawful attorneys and agents, with full power of substitution
and resubstitution, for him and in his name, place and stead, in any and all
capacities, to sign any and all amendments to the Company's Annual Report on
Form 10-K for the fiscal year ended December 31, 1995, and to file the same with
all exhibits thereto, and all other documents in connection therewith, with the
Securities and Exchange Commission, granting unto said attorneys and agents, and
each or any of them, full power and authority to do and perform each and every
act and thing requisite and necessary to be done, as fully to all intents and
purposes as he might or could do in person, hereby ratifying and confirming all
that said attorneys and agents, and each of them, or his substitute or
substitutes, may lawfully do or cause to be done by virtue hereof.
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS
REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE
REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED.
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
--------- ----- ----
<C> <S> <C>
/s/ JOHN L. WHITMIRE Chairman of the Board and Chief March 13, 1996
- --------------------------------------------- Executive Officer (Principal
(JOHN L. WHITMIRE) Executive Officer)
/s/ LARRY D. KALMBACH Vice President and Chief March 13, 1996
- --------------------------------------------- Financial Officer
(LARRY D. KALMBACH) (Principal Financial Officer)
/s/ DONALD M. MCMULLAN Vice President and Controller March 13, 1996
- --------------------------------------------- (Principal Accounting Officer)
(DONALD M. MCMULLAN)
/s/ GLENN A. COX Director March 13, 1996
- ---------------------------------------------
(GLENN A. COX)
/s/ SAUL A. FOX Director March 13, 1996
- ---------------------------------------------
(SAUL A. FOX)
/s/ EDWARD A. GILHULY Director March 13, 1996
- ---------------------------------------------
(EDWARD A. GILHULY)
/s/ JAMES H. GREENE, JR. Director March 13, 1996
- ---------------------------------------------
(JAMES H. GREENE, JR.)
</TABLE>
73
<PAGE> 76
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
--------- ----- ----
<C> <S> <C>
/s/ HENRY R. KRAVIS Director March 13, 1996
- ---------------------------------------------
(HENRY R. KRAVIS)
/s/ MICHAEL W. MICHELSON Director March 13, 1996
- ---------------------------------------------
(MICHAEL W. MICHELSON)
/s/ STANLEY P. PORTER Director March 13, 1996
- ---------------------------------------------
(STANLEY P. PORTER)
/s/ GEORGE R. ROBERTS Director March 13, 1996
- ---------------------------------------------
(GEORGE R. ROBERTS)
/s/ RICHARD R. SHINN Director March 13, 1996
- ---------------------------------------------
(RICHARD R. SHINN)
/s/ SELLERS STOUGH Director March 13, 1996
- ---------------------------------------------
(SELLERS STOUGH)
</TABLE>
74
<PAGE> 77
CONSENT OF INDEPENDENT ACCOUNTANTS
We hereby consent to the incorporation by reference in the Prospectuses
constituting part of Union Texas Petroleum Holdings, Inc.'s Registration
Statements on Forms S-8 (Nos. 33-26105, 33-44045, 33-13575, 33-21684, 33-59213
and 33-64928) and Form S-3 (No. 33-64049) of our report dated February 14, 1996,
appearing on page 33 of this Form 10-K.
PRICE WATERHOUSE LLP
Houston, Texas
March 12, 1996
S-1
<PAGE> 78
EXHIBIT INDEX
<TABLE>
<CAPTION>
EXHIBIT NO. DESCRIPTION
- --------------------- ------------------------------------------------------------------------
<S> <C>
10.103 Second Amendment to Union Texas Petroleum Savings Plan for Salaried
Employees
10.104 Second Amended and Restated 1981 Badak LNG Sales Contract, dated as of
August 3, 1995, between Pertamina, as Seller, and Chubu Electric Power
Co., Inc., The Kansai Electric Power Co., Inc., Osaka Gas Co., Ltd. and
Toho Gas Co., Ltd., as Buyers, with related letter agreement, dated
August 3, 1995, between Seller and Buyers
10.105 LNG Sales and Purchase Contract (Badak V), dated August 12, 1995,
between Pertamina and Korea Gas Corporation
10.106 LNG Sale and Purchase Contract (Badak VI), dated October 25, 1995,
between Pertamina and Chinese Petroleum Corporation
10.107 Badin-II Revised Petroleum Concession Agreement
21.1 List of Subsidiaries
27 Financial data schedule
</TABLE>
<PAGE> 1
SECOND AMENDMENT TO
UNION TEXAS PETROLEUM SAVINGS PLAN
FOR SALARIED EMPLOYEES
WHEREAS, Union Texas Petroleum Holdings, Inc. (the "Company") and
other Employing Companies have heretofore adopted and maintained the Union
Texas Petroleum Savings Plan For Salaried Employees, as amended and restated
effective January 1, 1993 (the "Plan") for the benefit of their eligible
employees; and
WHEREAS, the Company desires to amend the Plan on behalf of itself and
the Employing Companies;
NOW, THEREFORE, the Plan shall be amended as follows, effective as of
August 1, 1995, except as otherwise provided:
1. Paragraph (50) of Section 1.1 shall be deleted in its
entirety, and the following new Paragraph (50) shall be substituted therefor:
"(50) Valuation Dates: Each and every day of the Plan Year on which
the New York Stock Exchange is open for business."
2. Sections 3.1(g), 3.2, 4.2(a), and 4.2(b) shall be amended by
deleting the word "month" each and every place it appears in such Sections and
substituting therefor the phrase "payroll period."
3. Section 3.1(b) shall be amended by deleting the last sentence
of such Section and the following shall be substituted therefor:
"A Member who has elected to defer a portion of his Compensation may
change his deferral percentage (within the percentage limit set forth
in Paragraph (a) above), effective as of the first day of any month,
in accordance with the procedures and within the time period
prescribed by the Committee."
4. Section 3.1(c) shall be amended by deleting the last sentence
of such Section and the following shall be substituted therefor:
"A Member who so cancels his Compensation reduction agreement may
resume Compensation deferrals, effective as of the first day of any
month, in accordance with the procedures and within the time period
prescribed by the Committee."
5. Section 3.9(c) shall be amended by deleting from the first
sentence of such Section the phrase "as of the last day of the month in which
such Rollover Contribution is made" and substituting therefor the phrase "as
soon as administratively feasible after receipt by the Trustee."
<PAGE> 2
6. Section 4.3(a) shall be amended by deleting the last sentence
of such Section and the following shall be substituted therefor:
"Notwithstanding the foregoing, if a Fund is invested in shares of an
open-end mutual fund, the procedure set forth in this Paragraph shall
be adjusted to the extent necessary to correspond with such mutual
fund's net income (or net loss) allocation procedure. As soon as is
practical after the end of each month, the Trustee shall deliver to
the Committee a written statement of such determination as of the last
Valuation Date in the month."
7. Section 4.4(c) shall be amended by deleting from such Section
the word "not."
8. Section 5.1 of the Plan shall be deleted and the following
shall be substituted therefor:
"5.1 Investment of Accounts. Each Member shall designate, in
accordance with the procedures established from time to time by the
Committee, the manner in which the amounts allocated to each of his
Accounts (other than Company Contributions) shall be invested from
among the Funds made available from time to time by the Committee.
One of such Funds shall be an unsegregated fund invested in Company
Stock entitled the "Union Texas Petroleum Stock Fund." Pending
selection and purchase of the types of investments provided by a Fund,
contributions to a Fund may be invested in obligations of the United
States of America or in any short-term investments such as commercial
paper or certificates of deposit, or in a commingled, collective or
common trust fund consisting of such investments. With respect to
each of a Member's Accounts, such Member may designate one of such
Funds for all the amounts allocated to such Account or he may split
the investment of the amounts allocated to such Account between such
Funds in such increments as the Committee may prescribe; provided,
however, that Company Contributions shall be invested in accordance
with the provisions of Section 5.2."
9. Section 5.3 of the Plan shall be deleted and the following
shall be substituted therefor:
"5.3 Change of Investment Funds.
(a) A Member may change his investment designation for future
contributions to be allocated to any one or all of his Accounts,
subject to the limitations of Section 5.1. Any such change shall be
made in accordance with the procedures established by the Committee,
and the frequency of such changes may be limited by the Committee.
-2-
<PAGE> 3
(b) Subject to the provisions of this Paragraph, a Member may
elect to convert his investment designation with respect to the
amounts already allocated to one or more of his Accounts. Any such
conversion shall be made in accordance with the procedures established
by the Committee, and the frequency of such conversion may be limited
by the Committee. Amounts in the Union Texas Petroleum Stock Fund
attributable to Company Contributions allocated to such Fund after
September 30, 1987 may not be transferred unless the Member is age 55
or older."
10. Section 5.4(a) shall be amended by deleting the last sentence
of such Section and the following shall be substituted therefor:
"In the event that treasury or authorized but unissued shares of
Company Stock are purchased by the Trustee from Union Texas Petroleum
Holdings, Inc., the price per share shall be the closing price of the
Company Stock reported on the New York Stock Exchange for the date of
purchase or, if no sale occurred on such date, for the next preceding
day on which a sale occurred."
11. Section 5.4(b) of the Plan shall be deleted and the following
shall be substituted therefor:
"(b) For purposes of crediting contributions invested in the Union
Texas Petroleum Stock Fund, the credit shall be based on the cost per
share (including brokerage fees and transfer fees) of Company Stock
purchased by the Trustee for all Members for the Valuation Date for
which the contributions were made, and for this purpose contributions
of shares of Company Stock shall be valued at the closing price of
such stock reported on the New York Stock Exchange for the date of
contribution, or, if no sale occurred on such date, for the next
preceding day on which a sale occurred."
12. Section 5.4(c) shall be amended by deleting from the second
sentence of such Section the words "the Trustee may in its discretion" and
substituting therefor the words "the Committee may in its discretion."
13. Article VI and Sections 3.8(e), 7.2, 8.2, 8.4 and 9.1 shall be
amended by adding the phrase "most recent" immediately preceding "Valuation
Date" wherever "Valuation Date" appears in such Article and Sections.
14. Article VI and Sections 3.8(e), 7.2, 8.2, 8.4 and 9.1 shall be
amended by adding the phrase "coincident with or" immediately after "Valuation
Date" wherever "Valuation Date" appears in such Article and Sections.
15. Section 8.4(d) shall be amended by adding to such Section
immediately after the phrase "five consecutive years" the following:
-3-
<PAGE> 4
"or, if earlier, the end of the Plan Year during which the death of
such terminated Member occurs if such Member was not reemployed by the
Company between the date of his termination of employment and the date
of his death."
16. Section 8.4(e) shall be amended by deleting from the last
sentence of such Section the word "not."
17. Section 10.2(a)(2) shall be amended be adding the following
two sentences thereto:
"Periodic installment payments may be paid monthly, quarterly,
semi-annually or annually as selected by the Member. The Member may
change the term certain at any time after the Member's Benefit
Commencement Date and as often as the Member may elect provided that
the term certain selected by the Member does not exceed the
limitations contained herein."
18. Section 10.5 shall be amended by deleting from such Section
the following:
"The provisions of this Section shall apply only if the Member's
Eligible Rollover Distributions during the Plan Year are reasonably
expected to total $200 or more or, if less than 100% of the Member's
Eligible Rollover Distribution is to be a Direct Rollover, the Direct
Rollover is $500 or more."
19. Section 10.8 shall be amended by deleting from the second
sentence of such Section the word "not."
20. Sections 11.1(a), (b), (c), (d) and (e) of the Plan shall be
deleted and the following shall be substituted therefor:
"(a) A Member may withdraw from his Member Contribution
Account and Rollover Account any or all amounts held in such Accounts.
(b) A Member who has withdrawn all amounts in his Member
Contribution Account and Rollover Account may withdraw from his
Company Contribution Account any or all amounts held in such Account
which have been so held for twenty-four months or more, but not in
excess of his Vested Interest in such Account.
(c) A Member who has withdrawn all amounts in his Member
Contribution Account and Rollover Account and who has contributed to
or had Cash or Deferred Contributions made on his behalf to the Plan
(or the Allied Savings Plan) for at least sixty cumulative months may
withdraw from his Company Contribution Account an amount not exceeding
his Vested Interest in the then value of such Account.
-4-
<PAGE> 5
(d) Withdrawals from a Member's Company Contribution Account
shall be considered to come, first, from the Member's Vested Interest
in the portion of his Company Contribution Account attributable to
Company Contributions allocated on or before September 30, 1987, and,
second, from the Member's Vested Interest in the portion of his
Company Contribution Account attributable to Company Contributions
allocated after September 30, 1987.
(e) A Member who has attained age fifty-nine and one-half,
who has withdrawn all amounts in his Member Contribution Account,
Rollover Account and Company Contribution Account and who has
contributed to or had Cash or Deferred Contributions made to the Plan
on his behalf for at least sixty cumulative months may withdraw from
his Cash or Deferred Account an amount not exceeding the then value of
such Account. A Member who makes such a withdrawal may not again make
Cash or Deferred Contributions to the Plan for a period of six months
following such withdrawal."
21. Section 11.1(g) shall be amended by deleting from the first
sentence of such Section the phrase "as of any the last day of a month" and
substituting therefor the phrase "as soon as administratively feasible."
22. Effective September 1, 1995, Article XIV shall be amended by
deleting the first sentence thereof and substituting the following therefor:
"As a means of administering the assets of the Plan, the Company has
entered into a Trust Agreement with Vanguard Fiduciary Trust Company,
as Trustee."
23. Paragraph (c) in Section 15.3 shall be amended by deleting the
term "Option 3" and substituting therefor the phrase "Union Texas Petroleum
Stock Fund."
24. Effective June 1, 1995, Article XIX shall be amended by adding
a new Section 19.7 to read as follows:
"19.7 Plan Changes During Periods of Transition. Anything to
the contrary herein notwithstanding, the Committee may in its
discretion provide that, during and for the duration of any period of
transition as a result of a change of Trustees and as necessary to
ensure an orderly transition, (1) no distributions, withdrawals,
loans, execution of, change to, or revocation of a Compensation
reduction agreement, change of investment designation of future
contributions or transfer of amounts in Accounts from one Fund to
another Fund, or other Plan activity shall be permitted, or (2) any
such Plan activity shall be limited or restricted; provided that any
such temporary cessation, limitation, or restriction of Plan activity
shall be in compliance with all applicable law."
-5-
<PAGE> 6
25. Section 21.2(b) shall be deleted and the following shall be
substituted therefor:
"(b) Cash proceeds received by the Trustee from the sale or
exchange of any shares of Company Stock shall be invested by the
Trustee in such Fund or Funds, in such increments as the Committee may
prescribe, in accordance with directions obtained from Members at the
time of the receipt of such proceeds, which directives shall be
independent of the investment directions made by the Member pursuant
to Sections 5.1 and 5.3 hereof. If timely investment direction is not
received from a Member, such Member's interest in such cash proceeds
shall be invested in the Fund selected by the Committee."
26. Effective as of January 1, 1995, Section 11.1(f)(3) shall be
deleted and the following shall be substituted therefor:
"(3) payment of tuition, related educational fees, and room
and board expenses, for the next twelve months of post-secondary
education for the Member, the Member's spouse, children or dependents
(as defined in section 152 of the Code);"
27. As amended hereby, the Plan is specifically ratified and
reaffirmed.
EXECUTED this 22nd day of November, 1995.
UNION TEXAS PETROLEUM HOLDINGS, INC.
By: /s/ NEWTON W. WILSON, III
---------------------------------
Newton W. Wilson, III
General Counsel & Vice President - Administration
-6-
<PAGE> 1
SECOND AMENDED AND RESTATED 1981 BADAK LNG SALES CONTRACT
BETWEEN
PERUSAHAAN PERTAMBANGAN MINYAK DAN
GAS BUMI NEGARA (PERTAMINA),
as Seller
AND
CHUBU ELECTRIC POWER CO., INC.
THE KANSAI ELECTRIC POWER CO., INC.
OSAKA GAS CO., LTD.
TOHO GAS CO., LTD.,
as Buyers
<PAGE> 2
SECOND AMENDED AND RESTATED 1981 BADAK LNG SALES CONTRACT
The representatives of PERUSAHAAN PERTAMBANGAN MTNYAK DAN GAS BUMI NEGARA
(PERTAMINA) ("Seller") and Chubu Electric Power Co., Inc., The Kansai Electric
Power Co., Inc., Osaka Gas Co., Ltd. and Toho Gas Co., Ltd. ("Buyers") have
agreed to recommend to their respective managements and, in the case of Seller,
also to the Government of the Republic of Indonesia, the attached texts of the
following documents which they have each initialled today:
1. Second Amended and Restated 1981 Badak LNG Sales Contract
("Second A/R").
2. Schedule A.
3. Side Letter to Second A/R Re: A. HNS Convention; B. Omnibus
Agreement and Waiver Agreement; C. Definition of Business Day in
Japan; D. Price Transition; E. Pricing; F. Excess Capacity; and
G. Side Letter to Badak LNG Sales Contract, attaching a copy of
January 1, 1990 Side Letter Re: I Assistance to Buyers; II
Conditions of Use; III Transportation Force Majeure; IV
Transportation Coordination; and V Section 4.14(b)(i).
4. Letter Re: Deliverability of LNG from the Badak Facility.
These documents are subject to the approval of the respective managements of the
parties and, in the case of Seller, also to the approval of the Government of
the Republic of Indonesia, and shall not have legal effect until so approved
and signed.
Dated: June 22, 1995
For and on behalf of Seller For and on behalf of Buyers
/s/ unreadable /s/ unreadable
- --------------------------- ---------------------------
<PAGE> 3
SECOND AMENDED AND RESTATED 1981 BADAK LNG SALES CONTRACT
CONTENTS
<TABLE>
<CAPTION>
Page
<S> <C> <C> <C>
ARTICLE 1 - DEFINITIONS 1
ARTICLE 2 - SALE AND PURCHASE 8
ARTICLE 3 - SOURCES OF SUPPLY 9
ARTICLE 4 - LOADING AND TRANSPORTATION 11
ARTICLE 5 - ONSHORE FACILITIES 21
ARTICLE 6 - DURATION OF CONTRACT 22
ARTICLE 7 - QUANTITIES 23
ARTICLE 8 - CONTRACT SALES PRICE 32
ARTICLE 9 - TRANSFER OF TITLE 34
ARTICLE 10 - INVOICES AND PAYMENT 35
ARTICLE 11 - QUALITY 38
ARTICLE 12 - SCHEDULING 39
ARTICLE 13 - MEASUREMENTS AND TESTS 41
ARTICLE 14 - DUTIES AND TAXES 49
ARTICLE 15 - FORCE MAJEURE 50
ARTICLE 16 - ARBITRATION 53
ARTICLE 17 - APPLICABLE LAW 54
ARTICLE 18 - BUYERS' COORDINATOR AND REPRESENTATIVE 55
ARTICLE 19 - CONFIDENTIALITY 56
ARTICLE 20 - NOTICES 57
ARTICLE 21 - ASSIGNMENT 59
ARTICLE 22 - AMENDMENTS 60
ARTICLE 23 - SEVERALTY 61
ARTICLE 24 - DETAILS OF PERFORMANCE 62
ARTICLE 25 - SCOPE 63
ARTICLE 26 - COUNTERPARTS 64
ARTICLE 27 - EFFECTIVE DATE AND APPLICABILITY 65
SCHEDULE A - TESTING AND METHODS
</TABLE>
<PAGE> 4
SECOND AMENDED AND RESTATED 1981 BADAK LNG SALES
CONTRACT
This Badak LNG Sales Contract (the "Contract"), dated as of the 14th day of
April, 1981, amended and restated as of the 1st day of January, 1990 ("First
A/R"), is hereby further amended and restated as of the 3rd day of August, 1995
("Second A/R") by and between PERUSAHAAN PERTAMBANGAN MINYAK DAN GAS BUMI
NEGARA ("PERTAMINA"), a state enterprise of the Republic of Indonesia
("Seller"), on the one hand, and CHUBU ELECTRIC POWER CO., INC. ("Chubu
Electric"), THE KANSAI ELECTRIC POWER CO., INC. ("Kansai Electric"), OSAKA GAS
CO., LTD. ("Osaka Gas") and TOHO GAS CO., LTD. ("Toho Gas"), all corporations
organized and existing under the laws of Japan (hereinafter referred to
individually as "Buyer" and collectively as "Buyers"), on the other hand.
WITNESSETH:
WHEREAS :
1. Seller and Buyers have, from time to time, amended the Contract to
incorporate new or revised terms relating to the sale and purchase of
LNG; and
2. By Memorandum of Agreement Re: 1981 Badak LNG Sales Contract Extension
("1981 Extension MOA") dated as of October 6, 1994, and subsequent
agreements Seller and Buyers agreed to extend the Contract to March
31, 2011 on agreed terms and conditions and to amend and restate the
Contract to reflect such extension.
NOW, THEREFORE, Seller and each Buyer hereby agree to the following terms :
ARTICLE 1 _ DEFINITIONS
The terms or expressions below will have the following meanings in this
Contract:
1.1 Actual Cubic Foot
A volume equal to the volume of a cube whose edge is one foot.
<PAGE> 5
1.2 Actual Loading Time
As defined in Section 4.12(b).
1.3 Affiliate
As defined in Article 19.
1.4 Allowance
The quantity of LNG by which a Buyer reduces a Quantity Deficiency in
respect of a given calendar year pursuant to the provisions of Section
7.3(d).
1.5 Allowance Restoration Period
As defined in Section 7.3(d)(iv).
1.6 Allotted Loading Time
As defined in Section 4.12(a).
1.7 Annual Program
As defined in Section 12.1(a).
1.8 Arrival Temperature Requirement
As defined in Section 4.10.
1.9 Badak Facility
As defined in Section 5.2.
1.10 Base Rate
The rate of interest announced from time to time by Citibank, N.A.,
New York ("Citibank") as Citibank's base rate. The base rate may not
be the lowest rate charged by Citibank to its borrowers. If there is
any doubt as to the Base Rate for any period, a written confirmation
signed by an officer of Citibank shall conclusively establish the Base
Rate in effect for such period. In the event that Citibank shall for
any reason cease quoting a base rate as described above, then a
comparable rate shall be determined using rates then in effect and
shall be used in place of the said base rate.
1.11 British Thermal Unit (BTU)
The amount of heat required to raise the temperature of one
avoirdupois pound of pure water from 59.0 Degrees F to 60.0 Degrees F
at an absolute pressure of 14.696 pounds per square inch.
1.12 Business Day in Japan
Every day other than Saturdays, Sundays, National Holidays (including
compensatory
<PAGE> 6
days), and January 2 and 3.
1.13 Buyers' Coordinator
Japan Indonesia LNG Co., Ltd. or such other entity as may be
designated by Buyers pursuant to Article 18.
1.14 Buyer's Facilities
For the purposes of Section 15.1(a)(v) in respect of any Buyer, the
Receiving Facilities of such Buyer and such other facilities directly
related to the use of LNG which, if not operational, would reduce the
amount of LNG which such Buyer is able to receive hereunder.
1.15 Buyers' Representative
P.T. Jasa Enersi Pratama Nusantara or such other entity as may be
designated by Buyers pursuant to Article 18.
1.16 Buyers' Transportation Agreement
The Transportation Agreement between Buyers and Buyers' Transporter
for transporting LNG delivered under this Contract.
1.17 Buyers' Transporter
The Transporter designated in Buyers' Transportation Agreement.
1.18 Certificate
As defined in Section 3.2(a).
1.19 Contract Sales Price
As defined in Section 8.1.
1.20 Cubic Meter (CBM)
A volume equal to the volume of a cube whose edge is one meter.
1.21 Delivery Point
The point at the Loading Port at which the flange coupling of Seller's
loading line joins the flange coupling of the LNG loading manifold
onboard any LNG Tanker.
1.22 Demurrage Event
As defined in Section 4.13(a).
<PAGE> 7
1.23 ETA
Estimated time of arrival as defined in Section 4.6 (a).
1.24 Exercising Buyer
As defined in Section 7.3 (d)(i).
1.25 Fixed Quantity
As defined in Section 7.1.
1.26 Fixed Quantity Period
As defined in Section 7.1.
1.27 Force Majeure Deficiency
As defined in Section 7.6 (a).
1.28 G.P.A.
Gas Processors Association.
1.29 Gas Supply Area
The areas in East Kalimantan, Indonesia, covered by production sharing
contracts between Seller and Seller's Suppliers, and such other nearby
contract areas as Seller may designate from time to time.
1.30 Gross Heating Value
The quantity of heat expressed in British Thermal Units produced by
the complete combustion in air of one cubic foot of anhydrous gas, at
a temperature of 60.0 Degrees Fahrenheit and an absolute pressure of
14.696 pounds per square inch, with the air at the same temperature
and pressure as the gas, after cooling the products of the combustion
to the initial temperature of the gas and air, and after condensation
of the water formed by combustion.
1.31 Liquefied Natural Gas (LNG)
Natural Gas in a liquid state at or below its boiling point and at a
pressure of approximately one atmosphere.
<PAGE> 8
1.32 LNG Tanker
An ocean-going vessel, meeting the requirements of Section 4.2,
suitable for transporting LNG, which is used by Buyers for
transportation of LNG under this Contract.
1.33 Loading Port
The port located at the Badak Facility.
1.34 Make-Good LNG
As defined in Section 7.3 (d)(iv).
1.35 Make-Good Obligation
The obligation of a Buyer as set forth in Section 7.3 (d)(iv) to take
and pay for LNG in an amount (measured in BTU's) equal to each
Allowance exercised.
1.36 Make-Up LNG
As defined in Section 7.5.
1.37 Natural Gas
Any hydrocarbon or mixture of hydrocarbons consisting essentially of
methane, other hydrocarbons, and non- combustible gases in a gaseous
state and which is extracted from the subsurface of the earth in its
natural state, separately or together with liquid hydrocarbons.
1.38 1973 LNG Sales Contract
The LNG Sales Contract dated as of December 3, 1973, amended and
restated as of August 3, 1995, between Seller, on the one hand, and
Chubu Electric, Kansai Electric, Kyushu Electric Power Co., Inc.,
Nippon Steel Corporation, Osaka Gas and Toho Gas, on the other hand.
1.39 Ninety-Day Schedule
As defined in Section 12.2.
1.40 Notice of Readiness
As defined in Section 4.9.
1.41 Proved Remaining Recoverable Reserves
Reserves which have been proved to a high degree of certainty by
reason of actual completion, successful testing or in certain cases by
adequate core analyses, and which are defined areally by reasonable
geological interpretation of structure and known continuity of oil- or
gas-saturated material.
<PAGE> 9
1.42 Quantity Deficiency
As defined in Section 7.3(a).
1.43 Receiving Facilities
As defined in Section 5.1.
1.44 Restoration Quantities
As defined in Section 7.6(a).
1.45 Round-Up Request
As defined in Section 7.3 (a)(ii).
1.46 Seller's Facilities
For the purposes of Section 15.1(a)(iv), Natural Gas reservoirs or
(whether heretofore constructed or to be constructed) production
facilities in the field, the facilities for transportation of Natural
Gas from the field, and the Badak Facility.
1.47 Seller's Gas Supply Obligation
From time to time on any given date, the amount of Natural Gas
required to satisfy the remaining obligations of Seller on such date
to supply LNG or Natural Gas from the Gas Supply Area plus the amount
of Natural Gas from the Gas Supply Area required to supply any
additional commitment or commitments which Seller anticipates making.
1.48 Seller's Suppliers
In respect of portions of the LNG to be sold hereunder:
(a) Total Indonesie and Indonesia Petroleum, Ltd.;
(b) Virginia Indonesia Company, Lasmo Sanga Sanga Limited, OPICOIL
Houston, Inc., Union Texas East Kalimantan Limited, Universe
Gas & Oil Company, Inc. and Virginia International Company;
(c) Unocal Indonesia Company;
(d) Indonesia Petroleum, Ltd.; and
such other entities that may, from time to time, execute a Supply
Agreement with Seller; and any successors and assigns of any of the
aforesaid suppliers who shall have agreed in writing to be bound by
all of the obligations of their respective assignors under the
applicable Supply Agreement with Seller.
<PAGE> 10
1.49 Standard Cubic Foot (scf)
The quantity of Natural Gas, free of water vapor, occupying a volume
of one Actual Cubic Foot at a temperature of 60.0 Dregrees F and at an
absolute pressure of 14.696 pounds per square inch.
1.50 Statement of Cooling Time
As defined in Section 4.10.
1.51 Supply Agreement
As defined in Section 3.1.
1.52 Take-or-Pay Quantity
As defined in Section 7.5.
1.53 Unloading Ports
The ports at locations in or near Nagoya, Osaka and Himeji, and at
such other locations in Japan as may be agreed between Seller and
Buyers, where the Receiving Facilities are or will be constructed.
1.54 U.S.CPI
The United States Consumer Price Index (determined by reference to :
All Urban Consumers (CPI-U); Unadjusted U.S. City Average; All items;
with a base period of 1982-84 = 100) as published by the U.S.
Department of Labor, Bureau of Labor Statistics.
<PAGE> 11
ARTICLE 2 - SALE AND PURCHASE
Seller agrees to sell and deliver to the Delivery Point, and each Buyer agrees
to purchase, receive and pay for, or to pay for if not taken, LNG, in the
quantities and at the price and in accordance with the other terms and
conditions set forth in this Contract.
<PAGE> 12
ARTICLE 3 - SOURCES OF SUPPLY
3.1 Sources of Supply
The Natural Gas to be processed into LNG and sold hereunder is to be
produced from the Gas Supply Area. Seller represents that Seller will
maintain throughout the term hereof the right to sell all quantities
of LNG to be sold hereunder. In this connection, Seller represents
that it has executed or will execute from time to time, as required in
order to maintain the right to sell the quantities of LNG to be sold
hereunder, agreements with production sharing contractors of Seller
under which agreements such production sharing contractors make
available for sale hereunder their respective interests in the
quantities of LNG to be sold hereunder ("Supply Agreement").
Notwithstanding any reference to Seller's Suppliers in this Contract,
Seller is fully responsible for performance of all the obligations of
Seller hereunder.
3.2 Reserves of Natural Gas
(a) Seller has furnished Buyers with statements, each entitled
"Certificate" and each dated on or prior to May 31, 1994, of
DeGolyer and MacNaughton expressing its estimate of Proved
Remaining Recoverable Reserves of Natural Gas in the Gas
Supply Area. Seller represents that such estimated quantity is
in excess of Seller's Gas Supply Obligation as of the date of
this Contract. Hereafter and throughout the term of this
Contract, before committing additional Natural Gas from the
Gas Supply Area to sale or other utilization, Seller shall
secure from an independent petroleum engineering consultant
firm of recognized standing in the petroleum industry,
qualified by reputation and experience in estimating reserves
of oil and Natural Gas in subsurface reservoirs, the written
statement (the "Certificate") of such firm expressing its
estimate of Proved Remaining Recoverable Reserves of Natural
Gas in the Gas Supply Area in an amount at least equal to
Seller's Gas Supply Obligation. Seller shall provide Buyers
with copies of each Certificate of such independent petroleum
engineering consultant firm on which Seller relies in making
any such commitment for supply of Natural Gas from the Gas
Supply Area. Seller shall also furnish all supporting
documentation provided by such independent petroleum
engineering consultant firm in connection with the issuance of
such Certificate.
(b) If, during the term of this Contract, Seller obtains
information from its activities (including the activities of
Seller's production sharing contractors) in operating
<PAGE> 13
fields in the Gas Supply Area which indicates unforeseen
adverse changes in the Proved Remaining Recoverable Reserves
of Natural Gas in the Gas Supply Area, Seller will promptly
inform Buyers of such situation and will further inform Buyers
of any measures which Seller may be required to take in order
to fulfill its obligations under this Contract.
<PAGE> 14
ARTICLE 4 - LOADING AND TRANSPORTATION
4.1 Buyers' Obligation to Provide Transportation
Buyers shall provide, or cause to be provided, the transportation
required to transport all quantities of LNG to be sold and delivered
hereunder from the Loading Port.
4.2 LNG Tankers
Buyers will provide, or cause to be provided, for their performance
under this Contract, LNG Tankers compatible with the marine facilities
of the Badak Facility of up to approximately two-hundred ninety (290)
meters in length, up to approximately forty-six (46) meters in width,
and up to approximately eleven and one-tenth (11.1) meters draft,
which LNG Tankers shall be designed and at all times equipped and
manned so as safely to permit the loading of a full cargo in
approximately twelve (12) hours of pumping time and to accept cargo at
a rate up to approximately eleven thousand (11,000) CBM per hour being
the full design pumping rate of Seller's loading pumps (which rate
shall be subject to revision after mutual agreement). The provisions
of this Contract applicable to LNG Tankers shall apply whether any LNG
Tanker is owned and operated by Buyers or otherwise.
4.3 Loading Port Facilities
(a) Seller will provide a berth, and cause to be provided port
facilities, including a channel and turning basin, and cause
to be designated a holding anchorage, all capable of receiving
an LNG Tanker of the dimensions set forth in Section 4.2,
where such LNG Tanker may safely proceed to, lie at and depart
from, always afloat at all times of the tide. Seller shall not
be obligated to provide facilities for repair of LNG Tankers.
(b) Seller will provide facilities capable of loading LNG at an
approximate rate of ten thousand (10,000) CBM per hour at a
normal operating pressure of about forty-two and one-half
pounds per square inch gauge (42.5 psig) at the Delivery
Point. In any event, pressure at the Delivery Point shall not
exceed one hundred twenty pounds per square inch gauge (120
psig).
<PAGE> 15
(c) Loading Port facilities shall include:
(i) Shore tanks and loading lines for liquid nitrogen,
and pipelines and connections for the supply of fresh
water; and
(ii) Appropriate systems necessary for radio and telex
communications with the LNG Tankers.
4.4 Loading Port Obligations
(a) LNG Tankers shall utilize the Loading Port facilities subject
to observance of all relevant port regulations. Any tugs,
pilots or escort vessels required (or other support vessels
required in connection with the safe berthing of an LNG
Tanker) shall be employed at the sole risk and expense of the
LNG Tanker. Prior to each loading, Buyers' Transporter shall
be responsible for determining the availability of any
nitrogen, fuel, water and other utilities required by the LNG
Tankers at the Loading Port, which will be provided by Seller
on an as available basis for Buyers' Transporter's account.
(b) Buyers and/or Buyers' Transporter shall be responsible for
payment of amounts due for supplies and services requested by
masters of LNG Tankers and for normal port charges to the
extent such charges are uniformly applied to all LNG vessels
receiving exports of LNG from the Loading Port.
4.5 Cargo Loading
(a) The LNG to be sold and purchased hereunder shall be pumped
into LNG Tankers at the expense of Seller through manifold
strainers of sixty (60) mesh (or such other mesh as shall be
agreed from time to time by the parties) provided by the LNG
Tanker and, absent agreement of the parties or an unavoidable
circumstance, shall be in full cargo lots.
(b) The loading facilities provided by Seller shall include a
boil-off gas return system for receiving boil-off gas from LNG
Tankers. There shall be no charge for any natural gas
boiled-off from the LNG Tankers while berthed at the Loading
Port that is returned to shore. The LNG Tankers shall compress
such boil-off gas to the extent required to maintain the gas
pressure in the LNG Tanker's cargo tanks and the boil-off gas
return line within allowable operating limits during loading,
and Seller shall operate the boil-off gas return system in a
manner that will permit the gas pressure in the LNG Tanker's
cargo tanks to be maintained within the allowable operating
limits of such tanks.
<PAGE> 16
4.6 Notifications of Estimated Time of Arrival at Loading Port and Cooling
Requirements
(a) Buyers shall give Seller notice by telex or facsimile of the
date and hour on which each LNG Tanker departs from an
Unloading Port or drydock/repair port and the estimated time
of arrival ("ETA") at the Loading Port. Said notice shall be
submitted immediately after the LNG Tanker's departure from
the Unloading Port or drydock/repair port. Buyers shall
include in such notice to Seller a statement of:
(i) The estimated quantity of LNG that will be required
to cool the tanks to permit continuous loading of LNG
and the estimated time that will be required for such
cooling, both of which will be based upon the date
the LNG Tanker is expected to commence loading;
(ii) Any operational deficiencies in the LNG Tanker that
may affect its port performance; and
(iii) Requirements for nitrogen, fuel, water and other
utilities.
Buyers shall arrange for the LNG Tanker's master to
notify Seller regarding any change in the ETA of
twelve (12) hours or more. If the LNG Tanker's cargo
tanks should require cooling or if the cooling or
utilities requirements or the condition of the LNG
Tanker should change on account of circumstances
discovered after transmittal of the notice required
by this Section 4.6(a), the master of the LNG Tanker
shall give prompt notice thereof to Seller, setting
forth the information required by the second
preceding sentence, or amending any such information
previously given to Seller.
(b) Seventy-two (72) hours prior to the LNG Tanker's arrival at
the Loading Port, the LNG Tanker's master shall give notice by
telex to Seller stating its then ETA. If this ETA should
change by more than six (6) hours, the LNG Tanker's master
shall give notice of the corrected ETA promptly to Seller.
<PAGE> 17
(c) Forty-eight (48) hours prior to the LNG Tanker's arrival at
the Loading Port, the LNG Tanker's master shall give notice by
telex to Seller confirming or amending the last ETA notice. If
this ETA changes by more than six (6) hours, the LNG Tanker's
master shall give notice of the corrected ETA promptly to
Seller.
(d) Twenty-four (24) hours prior to the LNG Tanker's arrival at
the Loading Port, an ETA notice shall be sent by telex and
radio to Seller confirming or amending the last ETA notice. If
this ETA changes by more than two (2) hours, the LNG Tanker's
master shall give notice of the corrected ETA promptly to
Seller.
(e) A final ETA notice shall be sent by telex and radio five (5)
hours prior to the LNG Tanker's arrival at the Loading Port.
4.7 Berthing Assignments
Seller shall determine the berthing sequence of vessels at the Loading
Port in order to best ensure compliance with the overall loading
schedule of the Badak Facility (including the Annual Program and
Ninety-Day Schedules hereunder), and shall notify the masters of LNG
Tankers via the ship's agent of their berthing priority upon receipt
of Notice of Readiness.
4.8 Vessels not Ready for Loading
(a) If an LNG Tanker arrives which is not ready to load for any
reason, Seller may or may not allow it to berth. In the case
of an LNG Tanker only requiring cooldown to be ready to load,
Seller shall not defer berthing by reason thereof if either
such cooldown was provided for in the most recent Ninety-Day
Schedule or the cooldown time is not expected to exceed six
(6) hours. Whenever Buyers notify Seller that an LNG Tanker
will require cooldown, Seller shall make provision therefor in
the Ninety-Day Schedule as soon as Seller can do so without
disrupting the overall loading schedule or operations of the
Badak Facility.
(b) If any LNG Tanker previously believed to be ready for loading
or cooling is found to be unready after being berthed, Seller
may direct the master to vacate the berth and proceed to
anchorage, whether or not other vessels are awaiting a berth,
unless it appears reasonably certain that the LNG Tanker at
the berth can be readied within four (4) hours and Seller has
not concluded that such LNG Tanker is unsafe.
<PAGE> 18
(c) When the LNG Tanker at anchorage is ready, the master will
notify Seller. Seller shall assign a berth to any such LNG
Tanker or to any LNG Tanker awaiting cooldown at anchorage as
soon as Seller is able to do so without disrupting Seller's
loading requirements or operations.
4.9 Notice of Readiness
As soon as the LNG Tanker is securely moored at the berth or securely
anchored awaiting a berth, has received all necessary port clearances
and is able to receive LNG for loading or cooling, the master shall
give notice of readiness to Seller ("Notice of Readiness"); provided,
however, that in the event an LNG Tanker should arrive at the Loading
Port prior to the date established in the Ninety-Day Schedule (and any
revisions thereof except those made after the LNG Tanker has commenced
its voyage to the Loading Port unless made as a result of delays
caused by the operations of the LNG Tankers), Notice of Readiness
shall be deemed effective at the earlier of (i) 0:00 a.m. local time
on the scheduled loading date, or (ii) the time loading commences.
4.10 Tank Temperature for Loading and Statement of Cooling Time
Buyers shall cause Buyers' Transporter after each discharge of a cargo
at an Unloading Port to retain on board each LNG Tanker sufficient
LNG, based on normal operations of the LNG Tanker (subject to making
adequate provision for any LNG Tanker mechanical problems of which
Buyers' Transporter is aware), to maintain, for a period of not less
than twenty-four (24) hours after the later of (i) the actual arrival
or (ii) the scheduled arrival date (ignoring any revision to such date
made after the LNG Tanker has commenced its voyage to the Loading
Port) of such LNG Tanker at the Loading Port, a temperature in the
cargo tanks to permit continuous loading of LNG ("Arrival Temperature
Requirement"); provided, however, that the Arrival Temperature
Requirement shall not apply upon entry into service or in cases where
the LNG Tanker proceeds from an Unloading Port to the Loading Port by
way of a port at which either a drydock or significant repairs have
been carried out. When an LNG Tanker requires cooling, the master or
Buyers' Representative shall so inform Seller at the time of the first
notice under Section 4.6(a) and, second, at the time of the Notice of
Readiness. After the LNG Tanker has been cooled, the representatives
of both Buyers and Seller shall sign a statement of cooling time
("Statement of Cooling Time").
<PAGE> 19
4.11 Quantities for Purging and Cooling of Tanks
Quantities of LNG required to purge and cool each LNG Tanker to the
temperature that will permit continuous loading of LNG shall be
delivered by Seller without charge to Buyers upon the initial entry of
such LNG Tanker into service and upon its return to service after each
annual scheduled maintenance period (except that for a vessel
temporarily in service as an LNG Tanker to receive such quantities of
LNG without charge to Buyers, such vessel must remain in service for a
period of not less than four (4) continuous months). All other LNG
required by the LNG Tankers for purging and cooling shall be sold,
delivered and invoiced by Seller and paid for by the Buyer (or its
designee) scheduled to receive the cargo of LNG next to be loaded at
the Contract Sales Price applicable to such cargo, except that where
any LNG Tanker having met the Arrival Temperature Requirement needs
purging or cooldown due to an event which does not extend Allotted
Loading Time under Section 4.12(c), then the LNG required in
connection therewith shall be provided without charge. Such price
shall be applied to the total liquid quantities delivered for purging
and cooling, measured before evaporation of any part thereof occurs.
The parties will determine by mutual agreement the rates and pressures
for delivery of LNG for purging and cooling and the method for
determining quantities used for such operations. Quantities of LNG
used to bring the LNG Tankers to a temperature permitting continuous
loading of LNG shall not be applied against the quantities required to
be sold by Seller and taken, or paid for if not taken, by Buyers under
other provisions of this Contract.
4.12 Loading Time
(a) The allotted loading time for Seller to load each LNG Tanker
("Allotted Loading Time") shall be twenty- four (24) hours,
subject to adjustment as provided below.
(b) The actual loading time for each LNG Tanker ("Actual Loading
Time") shall commence (i) six (6) hours after the time when
the Notice of Readiness is received or deemed to be effective,
as defined in Section 4.9, or (ii) when the LNG Tanker is "all
fast alongside" the berth and ready to receive cooldown LNG or
cargo, whichever first occurs, and shall end when the loading
and return lines of the LNG Tanker are disconnected from
Seller's loading and return lines and all cargo papers
necessary for departure required to be furnished by Seller are
delivered on board in proper form and the LNG Tanker is
permitted to proceed to sea.
<PAGE> 20
(c) Allotted Loading Time shall be extended to include:
(i) The period during which proceeding from the
anchorage, berthing, loading or clearing of the LNG
Tanker to proceed to sea after completion of loading
is delayed, hindered or suspended by a Buyer, Buyers'
Transporter, LNG Tanker master, port authority or any
third party for reasons of safety, weather or
otherwise and over which Seller has no control;
(ii) The period of any delays attributable to the
operation of an LNG Tanker, including the period of
time such LNG Tanker: (1) awaits a berth by reason of
the exercise by Seller of its rights under Section
4.8, or (2) receives LNG for purging and cooldown
(except when: (A) the LNG Tanker met the Arrival
Temperature Requirement and (B) the purging and
cooldown is not due to an event which extends
Allotted Loading Time under this Section 4.12(c));
(iii) Any period during which berthing or loading of an LNG
Tanker is delayed, hindered or suspended by reason of
force majeure pursuant to Article 15 hereof; and
(iv) Any period of delay caused by occupancy of the berth:
(A) By a previous LNG Tanker, provided such
occupancy is for reasons attributable to such
LNG Tanker;
(B) By either a previous LNG Tanker or another
vessel on its scheduled loading date
(ignoring any change in the schedule of the
vessel occupying the berth made after
departure of the LNG Tanker from the
Unloading Port); or
(C) By either a previous LNG Tanker or another
vessel that arrived prior to the LNG Tanker
when the LNG Tanker arrived after its
scheduled loading date (ignoring any change
in the LNG Tanker's scheduled loading date
after departure of the LNG Tanker from the
Unloading Port), except that there shall be
no addition to Allotted Loading Time under
this clause (C) either: (1) for any period in
excess of twenty-four (24) hours or (2) if
the LNG Tanker arrived more than twenty-four
(24) hours prior to
<PAGE> 21
0:00 a.m. local time on the scheduled loading
date of the vessel occupying the berth
(unless loading of such vessel was necessary
in order to maintain production of the
liquefaction facilities).
4.13 Demurrage
(a) Subject to paragraph (b) below, if Actual Loading Time exceeds
Allotted Loading Time (as extended in accordance with Section
4.12(c)) in loading any LNG Tanker ("Demurrage Event"), Seller
shall pay to Buyers demurrage at the daily rate (which shall
be prorated for a portion of a day) provided in Buyers'
Transportation Agreement, but not to exceed the daily
demurrage rate applicable under the 1973 LNG Sales Contract at
the time of the Demurrage Event.
(b) If a Demurrage Event occurs, the Buyer concerned shall take
such actions which are prudent and reasonable to prevent any
modification of the Ninety-Day Schedule and any other
unloading schedule at the Unloading Port to which the LNG
Tanker is bound, including appropriate direction of the LNG
Tanker. In the event that the Demurrage Event causes the LNG
Tanker involved to be delayed in arriving at the Unloading
Port so that it is unable to commence unloading on the
scheduled unloading date (in effect at the time of the
Demurrage Event) or such delay requires the modification of
the date of commencement of unloading of any other LNG vessel,
any invoice from the Buyer concerned to Seller in accordance
with the provisions of Section 10.2 with respect to such
Demurrage Event shall remain in effect; otherwise, no payment
for the Demurrage Event shall be due and the Buyer concerned
shall notify Seller either that it is not invoicing Seller or
that it is canceling any invoice already submitted to Seller.
4.14 Effect of Loading Port Delays; Transportation Costs
(a) If an LNG Tanker is delayed in berthing and/or commencement of
loading for a reason which would not result in an extension of
Allotted Loading Time under Section 4.12(c), and if, as result
of such reason, the commencement of loading is delayed beyond
thirty (30) hours after Notice of Readiness has been given,
then, for each full hour by which commencement of loading is
delayed beyond such thirty- hour period, Seller shall pay
Buyer or its designee for boil-off during such delay at the
Contract Sales Price applicable to the cargo of LNG next to be
loaded. The hourly BTU boil-off rate to be applied for such
purpose
<PAGE> 22
shall be determined by actual average boil-off experience of
the LNG Tankers as determined at appropriate intervals, but
shall never exceed that quantity of LNG on board the LNG
Tanker at the commencement of the said thirty-hour period.
Buyers shall invoice Seller for amounts due under this Section
4.14(a) and Seller shall pay the invoice in accordance with
Article 10.
(b) If there should become due from Buyers to Buyers' Transporter
at any time any of the following:
(i) Any payment or payments on account of non-utilization
of an LNG Tanker resulting from an event or
circumstance of force majeure affecting Seller caused
by an LNG vessel other than an LNG Tanker, which
payment or payments:
(A) shall not exceed, on a daily basis, the daily
demurrage rate provided in Section 4.13 for
the first ninety (90) days;
(B) shall be payable for any days in excess of
one hundred eighty (180) days of such LNG
Tanker non-utilization caused by such Seller
force majeure at the rate provided in Buyers'
Transportation Agreement; provided that,
should Buyers' Transportation Agreement be
terminated with respect to the LNG Tankers by
reasons of such event of force majeure, the
payment shall be equal to the termination
payment provided for in Buyers'
Transportation Agreement; and provided,
further, that the basis for calculating all
payments referred to in this clause (B) is
reasonable when compared with the obligations
of Seller under Seller's transportation
arrangements entered into in support of its
obligations under the 1973 LNG Sales Contract
in the same circumstances; and
(C) shall, in no event, exceed the maximum amount
then available by way of P. and I. cover in
respect of the LNG vessel causing the damage,
and if amounts in respect of all damages
resulting from the incident which would be
recoverable by Seller from such P. and I.
cover exceed the maximum amount then
available by way of P. and I. cover, then
there shall be a proportionate reduction in
the amount payable under this clause (i) so
that such reduced
<PAGE> 23
amount bears the same relationship to the
maximum amount then available by way of P.
and I. cover as the amount otherwise payable
hereunder would bear to the total amount of
Seller's damages resulting from the incident
which are recoverable from such P. and I.
cover; or
(ii) Any payment or payments on account of Buyers' failure
to provide Buyers' Transporter with the minimum
quantities of LNG required under Buyers'
Transportation Agreement, if the deficiency is caused
by the failure of Seller to satisfy its obligations
under this Contract;
then, if and to the extent that the amount payable to
Buyers' Transporter has not been paid and is not
payable to Buyers under Section 4.13, such amount
shall be paid to Buyers by Seller. This paragraph
(b) shall not require Seller to pay any amount which
becomes payable to Buyers' Transporter as the result
of an event or circumstance of force majeure
affecting Buyers, or as the result of Buyers' breach
of their obligations under this Contract. It is
understood that no amount will be payable by Seller
under this paragraph (b) by reason of non-utilization
of an LNG Tanker caused by the fault or negligence of
such LNG Tanker or Buyers' Transporter. Any payments
under this Section 4.14(b) shall be in such amounts
as reflect any credits to Buyers for other revenues
earned by the LNG Tanker during the period of force
majeure.
Buyers shall invoice Seller for payments under this
paragraph (b) and Seller shall pay those invoices in
accordance with Article 10.
<PAGE> 24
ARTICLE 5 - ONSHORE FACILITIES
5.1 Receiving Facilities
Buyers have heretofore constructed or will construct LNG receiving
terminal facilities at the Unloading Ports, including, without
limitation, berthing and unloading facilities, LNG storage tanks,
vessel services facilities and regasification plants (the "Receiving
Facilities").
5.2 Badak Facility
Seller has heretofore constructed or will construct at Bontang, East
Kalimantan, liquefaction plant facilities to be used by Seller,
including, without limitation, gas transmission pipelines, processing
facilities, storage tanks, utilities, berthing and loading facilities
(the "Badak Facility").
<PAGE> 25
ARTICLE 6 - DURATION OF CONTRACT
The terms of this Contract shall continue in effect until the expiration of the
parties' respective obligations hereunder with respect to the sale and purchase
of LNG or the earlier termination of this Contract pursuant to Section 10.5. If
Seller and any Buyer or Buyers so agree at least seven (7) years before the
time this Contract would otherwise expire, the term of this Contract as to such
Buyer or Buyers may be extended on such terms and conditions as may be mutually
agreed.
<PAGE> 26
ARTICLE 7 - QUANTITIES
7.1 Required Deliveries
During each calendar year or portion thereof specified below (each
such period being called a "Fixed Quantity Period"), Seller shall sell
to each Buyer, and each Buyer shall purchase, receive and pay for, or
pay for if not taken, at the Contract Sales Price, a quantity of LNG
having a heating value as specified for such Buyer for such Fixed
Quantity Period (each such quantity being called a "Fixed Quantity")
as follows:
<TABLE>
<CAPTION>
Calendar Fixed Quantity Fixed Quantities for Each Buyer
Year Period (Billions of BTU's)
- --------- ------------- ------------------------------------------------------------
Chubu Kansai Osaka Toho Total
Electric Electric Gas Gas
-------- ------- ------- ----- ------
<S> <C> <C> <C> <C> <C> <C>
1983 Aug. 25-Dec. 31 14,685 12,301 4,767 6,366 38,119
1984-1989 Each Full Year 80,156 42,750 21,375 26,719 171,000
1990 Full Year 82,884 44,205 22,103 27,628 176,820
1991 Full Year 84,248 44,933 22,466 28,083 179,730
1992 Full Year 85,612 45,660 22,830 28,538 182,640
1993 Full Year 86,976 46,388 23,194 28,992 185,550
1994-2010 Each Full Year 88,340 47,115 23,558 29,447 188,460
2011 Jan. 1 - Mar. 31 19,906 10,601 5,300 6,655 42,462
</TABLE>
The above Fixed Quantities are subject to adjustment as provided in Section
7.3(a). After giving effect to any such adjustment, the term "Fixed Quantity"
shall mean the applicable Fixed Quantity as so adjusted, and the respective
obligations of Seller to sell, and of each Buyer to purchase, receive and pay
for, or pay for if not taken, Fixed Quantities of LNG in any Fixed Quantity
Period shall apply to the applicable Fixed Quantities as so adjusted.
7.2 Reallocation of Cargoes; Rate of Deliveries
(a) Each Buyer, upon appropriate notice to Seller, may reallocate
all or part of an LNG Tanker cargo from one Buyer to another
Buyer.
In case of such reallocation, the ownership of such cargo or
part thereof shall be transferred directly from Seller to the
new Buyer in place of the original Buyer, but the respective
Fixed Quantities of the Buyers concerned shall not be changed
and the cargo in question shall be deemed to be received by
the original Buyer in connection with its take or pay
obligations under Section 7.3(a).
<PAGE> 27
Each such reallocation shall be documented in a form to be
established by Seller and Buyers, executed by the original
Buyer and the Buyer which will actually receive the cargo,
which document will provide that the receiving Buyer will
assume and be responsible to Seller for performance of the
obligations of the original Buyer in respect of such cargo,
and that such cargo is deemed to be taken by the original
Buyer in connection with its take or pay obligations under
Section 7.3(a).
Buyers will exercise the right to reallocate cargoes in a
manner that will not materially disrupt the shipping
schedules at the Badak Facility.
(b) Within each Fixed Quantity Period, the quantities to be
delivered by Seller and received by Buyers at the Badak
Facility shall be delivered and received at rates and
intervals which are reasonably constant over the course of
such Fixed Quantity Period, after taking into account all
commitments of the Badak Facility and taking into
consideration the downtime, shipping and other matters
referred to in Article 12, so as to assure, as nearly as
practicable, an even production rate at the Badak Facility
and an even rate of deliveries at the Delivery Point.
7.3 Buyer's Obligation to Take or Pay
(a) If, during any Fixed Quantity Period, any Buyer should fail
to take the full Fixed Quantity applicable thereto, such
Buyer shall pay Seller, at the Contract Sales Price in effect
as of the last day of such Fixed Quantity Period, for the
quantities of LNG required to be purchased but which were not
taken by such Buyer during such Fixed Quantity Period (any
such quantity deficiency being called a "Quantity
Deficiency"), subject, however, to paragraphs (b), (c) and
(d) below and the following:
(i) If, after taking into account all adjustments
provided for in this Section 7.3 including any
Allowance that has been exercised, the Quantity
Deficiency of a Buyer at the end of any Fixed
Quantity Period amounts to less than 2.9 trillion
BTU's, the amount of such Quantity Deficiency shall
be carried forward and added to the Fixed Quantity
of such Buyer for the next succeeding Fixed Quantity
Period; provided that, notwithstanding the
foregoing, if the total Quantity Deficiency of those
Buyers whose Quantity Deficiency is less than 2.9
trillion BTU's shall
<PAGE> 28
exceed 5.8 trillion BTU's, the amount of
carry-forward for such Buyers shall be determined as
follows:
(A) Any Buyer who has a Round-Up Request denied
shall carry forward its Quantity Deficiency;
(B) Any Buyer, other than a Buyer to whom (A)
next above applies, shall carry forward the
amount of such Quantity Deficiency up to
1.45 trillion BTU's; and
(C) Any Buyer whose Quantity Deficiency has not
been fully carried forward under (A) or (B)
next above shall in addition carry-forward
its share of the amount equal to 5.8
trillion BTU's minus the total carry-forward
amount allowed under (B) above, allocated
among all such Buyers in proportion to the
amount by which each of their respective
Quantity Deficiencies exceeds 1.45 trillion
BTU's (calculated to the nearest million
BTU's).
The amount carried forward pursuant to this clause
(i) shall be deducted from the Quantity Deficiency
of such Buyer and each Buyer to whom this clause (i)
applies shall be subject to take or pay pursuant to
this Section 7.3 only if and to the extent any
Quantity Deficiency remains after such deduction.
(ii) If, at the time each Annual Program is developed,
the Quantity Deficiency of a Buyer for the
applicable year is estimated to amount to less than
a full cargo, such Buyer shall have the right to
request an increase in the quantities which such
Buyer wishes to take in such year in an amount
sufficient to fill out such cargo (such right being
herein referred to as a "Round- Up Request"). Any
such Round-Up Request shall not, however, increase
the Fixed Quantity of such Buyer. If Buyer does not
make a Round-Up Request, or if Seller elects not to
honor such Round-Up Request, the non-delivery of the
partial cargo of Fixed Quantity shall not constitute
a failure of Seller to make LNG available for sale
for the purpose of paragraph (b) below.
(iii) At the time the Annual Program is being prepared for
1994 or any subsequent year, the Fixed Quantities
shall be adjusted at the request of Buyers to effect
the acceleration by one year of up to 2,910 billion
<PAGE> 29
BTU's if necessary to ensure that, taking into
account scheduled drydockings, Buyers have adequate
shipping capacity to transport the Fixed Quantities
during the year following that for which the Annual
Program is being prepared. Such acceleration shall
be effected by an appropriate increase to the Fixed
Quantity of a single Buyer or appropriate increases
to the Fixed Quantities of all or a number of
Buyers, as specified in such Buyers' request.
Corresponding decreases shall be made to the Fixed
Quantity or Fixed Quantities of the same Buyer(s)
for the Fixed Quantity Period following the Fixed
Quantity Period during which such acceleration
occurs.
(iv) If, at the end of any Fixed Quantity Period, a Buyer
has purchased and received quantities of LNG
hereunder in excess of the Fixed Quantity of such
Buyer for such Fixed Quantity Period other than
Make-Up LNG, Make-Good LNG or Restoration
Quantities, the excess shall be applicable to reduce
the Fixed Quantity of such Buyer for the next
succeeding Fixed Quantity Period.
(b) The obligation (set forth in paragraph (a) above) of each
Buyer with regard to any Fixed Quantity Period to pay for
Fixed Quantities not taken shall be reduced by the quantity
of LNG which such Buyer was unable to purchase because of an
event of force majeure as defined in Article 15 affecting
either Seller or such Buyer or because of Seller's failure
for any other reason to make such quantity available for sale
in accordance with this Contract.
(c) In calculating the quantity of LNG delivered by Seller and
purchased by a Buyer for each Fixed Quantity Period,
quantities delivered and purchased within the first seven (7)
days of the next following Fixed Quantity Period shall be
included, provided such quantities were scheduled in the
Annual Program for the Fixed Quantity Period with respect to
which the calculation is being made.
(d) The obligation of a Buyer pursuant to paragraph (a) above to
pay for quantities not taken may be reduced by the exercise
of an Allowance as follows:
(i) Each Allowance must be exercised by notice in
writing given to Seller by Buyers' Coordinator,
which will act as agent for Buyers in
<PAGE> 30
connection with the exercise of all Allowances. A
notice of the exercise of an Allowance given by
Buyers' Coordinator shall be deemed to have both the
authority of the Buyer on whose behalf it is
expressed to be given (the "Exercising Buyer") and
the consent of all other Buyers. No purported direct
exercise of an Allowance by a Buyer shall be valid.
A notice of exercise of an Allowance must be
received by Seller on or before January 12 of the
year following the Fixed Quantity Period in respect
of which such Allowance is exercised.
(ii) Each notice of exercise of an Allowance shall
specify the Exercising Buyer and the quantity of LNG
by which such Buyer's obligation to take and/or pay
during the relevant Fixed Quantity Period is to be
reduced.
(iii) No Allowance can be exercised which would result in
the aggregate Allowances then outstanding for all
Buyers during any Fixed Quantity Period after 1994
being in excess of 9,423 billion BTU's. Subject to
the provisions of subparagraph (viii) below, an
Allowance (or portion thereof) is outstanding until
either the Make-Good Obligation pursuant to
subparagraph (iv) below is satisfied or payment in
respect thereof is made pursuant to subparagraph
(vi) below.
(iv) Each Allowance shall be made good in full (even if
it amounts to a fractional portion of a full cargo
lot) by the purchase of an equal quantity of LNG in
excess of Fixed Quantities ("Make-Good LNG") within
a period commencing January 1 of the year following
the Fixed Quantity Period in relation to which such
Allowance was exercised and ending with the earlier
of the expiration of five (5) calendar years or June
30, 2011 ("Allowance Restoration Period"). No Buyer
may satisfy a Make-Good Obligation or any part
thereof during a Fixed Quantity Period until it
shall first have taken its Fixed Quantity for such
Fixed Quantity Period. If a Buyer has more than one
Allowance outstanding, the Make-Good Obligations in
respect thereof shall be satisfied in the same
chronological order in which such Allowances were
exercised. One or more Buyers may satisfy the
Make-Good Obligation with respect to an Allowance
exercised by another Buyer.
<PAGE> 31
(v) Every request for Make-Good LNG shall be made by
Buyers' Coordinator on behalf of a named Buyer in
accordance with Section 12.1 and shall specify the
Allowance to which it relates. Each such request
shall be deemed to have the authority of the named
Buyer and, if the named Buyer is not the Exercising
Buyer, of the Exercising Buyer.
(vi) If, at the expiration of the Allowance Restoration
Period, a Make-Good Obligation has not been
satisfied in full, the Exercising Buyer (whether or
not a Buyer other than the Exercising Buyer was
named in any relevant request for Make-Good LNG)
shall pay for any unsatisfied portion of the
Make-Good Obligation at the Contract Sales Price in
effect as of the last day of such Allowance
Restoration Period. The Buyer shall have the right
to request Make-Up LNG pursuant to Section 7.5 with
respect to any such payment.
(vii) Seller shall not be obligated to reserve any LNG
production or shipping capacity for the purposes of
permitting Buyers to satisfy Make-Good Obligations.
(viii) In the event that Buyers' Coordinator requests
quantities of LNG to satisfy a Make-Good Obligation
on behalf of a Buyer or Buyers which Seller is
unable to make available for any reason, including
force majeure, the following provisions shall apply:
(A) The Exercising Buyer shall be relieved from
the obligation pursuant to subparagraph (vi)
above to pay for such requested quantities
as of the expiration of the Allowance
Restoration Period relating thereto, except
in the case where subparagraph (viii)(C)
below requires such payment;
(B) Such requested quantities shall be deemed
not outstanding for the purposes of
subparagraph (iii) above until Seller shall
(whether during or after the Allowance
Restoration Period) have offered the same to
such Buyer but shall then be outstanding if
such Buyer does not accept such offer; any
change in the quantity outstanding due to a
failure to accept such an offer shall not
result in an acceleration of any then
outstanding Make-Good Obligation; and
<PAGE> 32
(C) Such requested quantities shall be scheduled
for delivery at any time prior to June 30,
2011 as mutually agreed by Seller and the
Buyer having the Make-Good Obligation. If
such requested quantities have not been
scheduled as of the end of the last Fixed
Quantity Period and should Seller be unable
to deliver such requested quantities during
the three (3) months following the last
Fixed Quantity Period, Buyer shall have no
further obligation in respect thereof. If
Seller gives Buyer reasonable notice that
such requested quantities are available
during such three-month period but Buyer
does not take such quantities, Buyer shall
then make the payment required under
subparagraph (vi) above.
(e) A reduction shall be made to any Quantity Deficiency
equal to the amount by which such Quantity
Deficiency resulted from a partial loading of an LNG
Tanker during the relevant Fixed Quantity Period due
to reasons attributable to Seller.
7.4 Allocation of Deliveries between Buyers and Other Purchasers
(a) Whenever deliveries of LNG by Seller under this Contract must
be reduced by reason of an event or circumstance of force
majeure as defined in Article 15 affecting Seller's ability
to produce or load LNG from the Badak Facility, an allocation
of quantities then available for sale at the Badak Facility
will be made between Buyers and other purchasers of LNG from
the Badak Facility. At such times the total quantities
available for sale from the Badak Facility shall be allocated
among the purchasers therefrom (including the Buyers) pro
rata in the ratio of their respective quantities which are
eligible for allocation as provided below. The quantities
eligible for such allocation shall, as to Buyers, be the
Fixed Quantities to be purchased hereunder during the period
of such force majeure and, as to other purchasers, be those
fixed or contract quantities of LNG which are committed for
sale from the Badak Facility during the period of such force
majeure in satisfaction of Seller's contracts with other
purchasers which provide for sales of LNG over a term of at
least fifteen (15) years.
(b) If such an event of force majeure does not preclude full
production and loading of all Fixed Quantities under the
allocation formula described in paragraph (a) above but is of
such an extent as to prevent Seller from producing and
loading all Make-Up LNG, Make-Good LNG and Restoration
Quantities scheduled for
<PAGE> 33
delivery from the Badak Facility to Buyers and equivalent
quantities scheduled for delivery from the Badak Facility to
other purchasers under LNG sales contracts providing for
deliveries over a term of at least fifteen (15) years,
quantities of such LNG as are available shall be allocated
between Buyers and such other purchasers in proportion to the
respective quantities so scheduled.
7.5 Take-or-Pay Make-Up
If, pursuant to Section 7.3(a) or Section 7.3(d)(vi), a Buyer shall
have paid for any quantity of LNG which was not taken by such Buyer
("Take-or-Pay Quantity"), then, in any subsequent year, the said
Buyer may purchase up to an equal quantity of LNG from Seller as
make-up LNG ("Make-Up LNG") (to the extent not previously made up). A
Buyer may request Make-Up LNG by giving written notice to Seller as
provided in Section 12.1. If, during any year for which Make-Up LNG
has been requested, (i) Seller has uncommitted quantities of LNG
available for such purposes and (ii) such Buyer shall have first
taken and paid for its Fixed Quantity for such year, then Seller
shall sell to such Buyer the quantity of Make-Up LNG requested. A
Buyer's right to purchase Make-Up LNG under this Section 7.5 shall
expire on March 31, 2012 unless such Buyer shall have requested
Make-Up LNG during the preceding twelve (12) months and Seller shall
have had insufficient uncommitted LNG to meet such request. In such
circumstances, the parties shall consult to agree upon a deferred
schedule for Buyer to take delivery of any outstanding balance of
Take-or-Pay Quantity not made up by March 31, 2012. Each Buyer shall
pay for Make-Up LNG at the Contract Sales Price in effect as of the
date of delivery, reduced by the amount previously paid on account of
all or that part of the Take-or-Pay Quantity being made up by such
sale. Take-or-Pay Quantities shall be made up, and prior payments
applicable thereto applied, in the same chronological order in which
such quantities accrued.
7.6 Force Majeure Deficiency
(a) If, during any Fixed Quantity Period or Fixed Quantity
Periods, all or any portion of the Fixed Quantity of LNG
required to be taken by any Buyer therein is not delivered by
Seller or taken by such Buyer by reason of force majeure as
defined in Article 15 (any such quantity not taken for such
reason being called a "Force Majeure Deficiency"), Seller and
the Buyer or Buyers concerned shall each make best efforts to
restore the Force Majeure Deficiency in full by Seller
selling and the Buyer or Buyers purchasing such quantities of
LNG prior to the expiration of the last Fixed Quantity
Period. The restoration quantities so agreed ("Restoration
Quantities") will be scheduled for delivery pursuant to
Article 12 at the mutual convenience of the parties. Such
<PAGE> 34
Restoration Quantities shall be subordinate to Make-Good LNG
requested pursuant to Section 7.3(d) and Make-Up LNG
requested pursuant to Section 7.5. Each Buyer shall pay for
Restoration Quantities at the Contract Sales Price in effect
as of the date of delivery.
(b) If an event of force majeure relieves or delays the
performance by any Buyer of its obligations under this
Contract and causes a reduction in deliveries of LNG and
Seller sells to third parties quantities of LNG which Buyers
are unable to purchase, then the Force Majeure Deficiency
shall be reduced by the amount, if any, that the Seller's Gas
Supply Obligation (including amounts so sold to third
parties) exceeds the estimate of Proved Remaining Recoverable
Reserves stated in the most recent Certificate as a result of
such sales.
7.7 Allocation of Make-Good LNG, Make-Up LNG and Restoration Quantities
Whenever Make-Good LNG is requested under Section 7.3(d), Make-Up LNG
is requested under Section 7.5 and/or Restoration Quantities are
requested under Section 7.6(a) by a Buyer or Buyers, and quantities
are requested for similar purposes by other purchasers from the Badak
Facility, and uncommitted quantities of LNG are not available from
the Badak Facility to meet all such requests, then the quantities of
LNG which are available from the Badak Facility for such purposes
shall be allocated, as between such Buyer or Buyers on the one hand
and such other purchasers on the other hand, based on the proportion
of the contract quantities of each requesting purchaser to the total
of the contract quantities of all of the requesting purchasers.
7.8 Order of Priority of Make-Good LNG and Make-Up LNG
Make-Good LNG requested under Section 7.3(d) and Make-Up LNG
requested under Section 7.5 shall be delivered in the priority
specified by Buyers' Coordinator.
<PAGE> 35
ARTICLE 8 - CONTRACT SALES PRICE
8.1 Contract Sales Price
The contract sales price applicable to the quantities of LNG to be
sold and delivered at the Delivery Point and to any quantities of LNG
required to be taken but which are not taken and are required to be
paid for by a Buyer under this Contract, expressed in United States
Dollars per million British Thermal Units (U.S.$/MMBTU), ("Contract
Sales Price") and shall be determined in accordance with the
following provisions of this Article 8.
The Contract Sales Price is subject to adjustment from time to time
according to the following provisions of this Article 8 and as
adjusted and in effect at any time shall be the Contract Sales Price.
The Contract Sales Price to be applied to the BTU's comprising each
cargo shall be that Contract Sales Price in effect as of the date of
completion of loading of such cargo.
8.2 Contract Sales Price and Adjustments Thereto
(a) The Contract Sales Price ("CSP"), as adjusted from time to
time, shall be calculated according to the following formula:
9 A 1 U.S.CPIn
CSP = 0.982 [--- (Po x ----------)+ --- (Po x --------) + C]
10 U.S.$18.00 10 U.S.CPIo
where:
CSP = the Contract Sales Price (expressed
in U.S.$/MMBTU);
Po = U.S.$ 3.06/MMBTU;
A = the arithmetic average of the
realized export prices per barrel
in U.S. Dollars, f.o.b. Indonesia,
of all field classifications of
Indonesian crude oils then being
sold and exported by PERTAMINA,
except premiums and except such
prices for spot sales;
Po = U.S.$ 3.24/MMBTU;
U.S.CPIn = in respect of the applicable
calendar year, the average of the
monthly values of U.S.CPI for the
twelve-month period commencing with
the month of November, fourteen
(14) months prior to the beginning
of the applicable calendar year,
and ending with the month of
<PAGE> 36
October, three (3) months prior to
the commencement of the applicable
calendar year;
U.S.CPIo = 143.8, being the arithmetic average
of the monthly values of U.S.CPI
for the twelve-month period,
November 1992 through October 1993;
and
C = U.S.$ 0.012/MMBTU.
(b) An adjustment of the Contract Sales Price to reflect any
change in U.S.CPI shall be made on and shall be effective as
of January 1 of each calendar year, and further adjustments
of the Contract Sales Price shall be made as of each
effective date on which:
(i) the realized export prices of more than one of the
field classifications of Indonesian crude oils sold
by PERTAMINA shall have changed from the respective
prices therefor included in the last preceding
determination of "A" made pursuant to Section 8.2
(a); or
(ii) two or more field classifications of such crude oils
shall have been added to or deleted from the crude
oils being sold by PERTAMINA since the date of the
last preceding determination of "A" made pursuant to
Section 8.2(a).
Procedures for verifying changes in the realized export
prices of all Indonesian crude oils and for determining the
effective date of any adjustment of the Contract Sales Price
shall be separately agreed upon by Seller and Buyers.
(c) Seller and Buyers shall agree separate procedures for
handling corrections, revisions or changes in the calculation
of U.S.CPI. It is agreed that if at any time the U.S.
Department of Labor, Bureau of Labor Statistics discontinues
publishing a report on U.S.CPI values, then Seller and Buyers
shall agree upon an index method that reflects inflation in
the United States of America's consumer prices to replace the
discontinued U.S.CPI report.
<PAGE> 37
ARTICLE 9 - TRANSFER OF TITLE
Delivery shall be deemed completed and title and risk of loss shall pass from
Seller to the purchasing Buyer as the LNG reaches the Delivery Point.
<PAGE> 38
ARTICLE 10 - INVOICES AND PAYMENT
10.1 Invoice and Cargo Documents
Promptly after completion of loading of each LNG Tanker, Seller, or
its representative, shall furnish to the receiving Buyer, or Buyers'
Representative, a certificate of quantity loaded together with such
other documents concerning the cargo as may be reasonably requested
by Buyers for the purpose of Japanese customs clearance. Seller shall
further, within forty-eight (48) hours of completing the loading,
cause a laboratory analysis to be completed to determine the quality
of the LNG and shall promptly furnish Buyer, or Buyers'
Representative, a certificate with respect thereto together with
details of the calculation of the number of BTU's sold. Promptly upon
completion of such analysis and calculation, Seller, or its
representative, shall furnish by telex or telegram to the receiving
Buyer an invoice, stated in U.S. Dollars in the amount of the
Contract Sales Price for the number of BTU's sold together with
component MOL fractions, temperature, pressure and volume delivered.
At the same time, Seller shall send Buyer a signed copy of the
invoice and relevant documents showing the basis for the calculation
thereof.
10.2 Other Invoices
In the event that any monies are due from one party to the other
hereunder, including, without limitation, amounts payable pursuant to
Section 7.3 on account of Fixed Quantities of LNG required to be
purchased but which were not taken by a Buyer, then the party to whom
such monies are due shall furnish or cause to be furnished an invoice
therefor and relevant documents showing the basis for the calculation
thereof. The procedure set forth in Section 10.1 for sending a copy
of such invoice by telex or telegram may be followed.
10.3 Invoice Due Dates, etc.
Each invoice to a Buyer referred to in Section 10.1 above shall
become due and payable by such Buyer on the eighth (8th) Business Day
in Japan after the date on which the telex/telegraphic copy of such
invoice has been received by such Buyer in Japan.
Each other invoice to a Buyer hereunder shall become due and payable
by such Buyer within twenty (20) calendar days after the date of
Buyer's receipt of such invoice in Japan.
Each invoice delivered to Seller shall become due and payable on the
fourteenth (14th) calendar day after Seller's receipt thereof.
<PAGE> 39
If any invoice due date is not a Business Day in Japan, such invoice
shall become due and payable on the next day which is a Business Day
in Japan.
In the event the full amount of any invoice is not paid when due, any
unpaid amount thereof shall bear interest from the due date until
paid, at an interest rate, compounded annually, two percent (2%)
greater than the Base Rate in effect from time to time during the
period of delinquency. Such interest rate shall be adjusted up or
down, as the case may be, to reflect any changes in the Base Rate as
of the dates of such changes in the Base Rate.
10.4 Payment
Each Buyer shall pay, or cause to be paid, in U.S. Dollars all
amounts which become due and payable by such Buyer pursuant to any
invoice issued hereunder to a bank account or accounts in the United
States to be designated by Seller. Seller shall pay, or cause to be
paid, in U.S. Dollars all amounts which become due and payable by
Seller pursuant to any invoices issued hereunder to a bank account in
Japan designated by Buyers. The paying party shall not be
responsible for a designated bank's disbursement of amounts remitted
to such bank, and a deposit in immediately available funds of the
full amount of each invoice with such bank shall constitute full
discharge and satisfaction of the obligations under this Contract for
which such amounts were remitted. Each payment of any amount owing
hereunder shall be in the full amount due without reduction or offset
for any reason, including, without limitation, taxes, exchange
charges or bank transfer charges.
Transfer of funds to the bank in the United States, effected from
Japan before the close of business in Japan on or before the due date
of any invoice, shall be deemed timely payment notwithstanding that
such U.S. bank cannot credit such transfer as immediately available
funds for a period of up to fourteen (14) hours by reason of the time
difference between Japan and the United States or for one or more
days which are not banking days in the United States.
10.5 Seller's Rights Upon Buyer's Failure to Make Payment
If payment of any invoice for quantities of LNG sold hereunder or for
Fixed Quantities of LNG not taken and for which a Buyer is obligated
to pay pursuant to this Contract is not made within sixty (60) days
after the due date thereof, Seller shall be entitled, upon giving
thirty (30) days' written notice to such Buyer, to suspend subsequent
sales to such Buyer until the amount of such invoice and interest
thereon has been paid, and such Buyer shall not be entitled to any
make-up rights in respect of such suspended sales. If any such
invoice is not paid within one hundred twenty (120) days after the
due date thereof, then, subject to the further provisions of this
Section 10.5, Seller shall have the right, at Seller's election, upon
not less than eighty
<PAGE> 40
(80) days' notice to Buyer or Buyers, as the case may be, to exercise
either of the following options:
(i) Seller may terminate this Contract in respect of the
defaulting Buyer only, in which event this Contract shall
continue in effect between Seller and the other Buyers just
as though the defaulting Buyer had never been a party and the
quantities of LNG thereafter to be purchased and received by
such defaulting Buyer had never been included in this
Contract; or
(ii) Seller may terminate this Contract in its entirety as to
Buyers unless, prior to such termination, arrangements shall
have been made which are satisfactory to Seller for the
payment of all amounts owed Seller by the defaulting Buyer
and for the assumption of the LNG quantity and other
obligations of the defaulting Buyer under this Contract by
one or more Buyer(s) not defaulting.
Termination by Seller under clause (i) or (ii) above shall become
effective upon the date specified in such notice from Seller. Any
such termination shall be without prejudice to any other rights and
remedies of Seller arising hereunder or by law or otherwise,
including the right of Seller to receive payment of all obligations
and claims which arose or accrued prior to such termination or by
reason of such default by a Buyer or Buyers.
10.6 Disputed Invoices
In the event of disagreement concerning any invoice, the invoiced
party shall make provisional payment of the total amount thereof and
shall immediately notify the other party of the reasons for such
disagreement, except that, in the case of obvious error in
computation, the correct amount shall be paid disregarding such
error. Invoices may be contested or modified only if, within a
period of ninety (90) days after receipt thereof, Buyer or Seller
serves notice on the other questioning their correctness. If no such
notice is served, invoices shall be deemed correct and accepted by
both parties. Promptly after resolution of any dispute as to an
invoice, the amount of any overpayment or underpayment shall be paid
by Seller or Buyer to the other, as the case may be, plus interest at
the rate provided in Section 10.3 from the date payment was due to
the date of payment.
<PAGE> 41
ARTICLE 11 - QUALITY
11.1 Gross Heating Value
The LNG when delivered by Seller to Buyers shall have, in a gaseous
state, a Gross Heating Value of not less than 1065 BTU per Standard
Cubic Foot and not more than 1165 BTU per Standard Cubic Foot. The
expected range will be between 1105 and 1160 BTU per Standard Cubic
Foot.
11.2 Components
The LNG delivered by Seller to Buyers shall, in a gaseous state,
contain not less than eighty-five molecular percentage (85 MOL%) of
methane (CH4) and, for the components and substances listed below,
such LNG shall not contain more than the following:
A. Nitrogen (N2), 1.0 MOL%.
B. Butanes (C4) and heavier, 2.00 MOL%.
C. Pentanes (C5) and heavier, 0.10 MOL%.
D. Hydrogen sulfide (H2S), 0.25 grains per 100 Standard Cubic
Feet (0.25 grains/100 scf).
E. Total sulfur content, 1.3 grains per 100 Standard Cubic Feet
(1.3 grains/100 scf).
Although the LNG which Seller delivers to Buyers is permitted to
contain the sulfur concentrations shown in clauses D and E above,
under normal operating conditions at the Badak Facility, Seller would
expect such concentrations to be materially less.
Should any question regarding quality of the LNG arise, Buyers and
Seller shall consult and cooperate concerning such questions.
<PAGE> 42
ARTICLE 12 - SCHEDULING
12.1 Annual Program
(a) Not later than ninety (90) days prior to the beginning of
each calendar year commencing with the year in which the
first Fixed Quantity Period occurs, Seller shall give written
notice to Buyers of the anticipated quantities of LNG to be
available for sale hereunder from the Badak Facility for each
calendar quarter of the next calendar year, specifying any
scheduled downtime of the Badak Facility. On or before
October 15 of each year in which such notice is given, each
Buyer shall advise Seller in writing of: (i) the quantities
such Buyer wishes to take during each calendar quarter of the
following year, specifying the amount of any Make-Up LNG
requested pursuant to Section 7.5 and any Restoration
Quantities in excess of Fixed Quantities requested pursuant
to Section 7.6(a), and (ii) any planned downtime for
Receiving Facilities, Buyers' shipping capacity and scheduled
drydocking for LNG Tankers. In addition, by October 15 of
each year, Buyers' Coordinator shall request any Make-Good
LNG pursuant to Section 7.3 (d).
Seller and Buyers shall thereupon consult together with a
view to reaching agreement by December 1 of the same year and
Seller shall issue a programming schedule, including
provisional loading dates, for quantities sold hereunder to
be loaded in full cargo lots at the Badak Facility during
each calendar month during the following year (the "Annual
Program"), and in so doing Seller and Buyers shall take into
consideration the contents of the above notices. The Annual
Program shall take into account Seller's commitments to other
purchasers of LNG from the Badak Facility. Such Annual
Program and the Ninety-Day Schedules referred to below (and
any revisions thereof) are intended to assist the parties in
planning their respective operations during the periods
involved. The content of the Annual Program and Ninety-Day
Schedules shall not reduce the entitlement of any party
during any Fixed Quantity Period to sell and be paid for, or
to purchase and receive, as the case may be, the quantities
of LNG required under Article 7 to be sold and paid for
during such Fixed Quantity Period. Seller and Buyers will
each take all appropriate steps to carry out each Annual
Program and Ninety-Day Schedule.
<PAGE> 43
(b) An Annual Program shall be amended to reflect a request for:
(i) Make-Good LNG relating to an Allowance exercised in
respect of the immediately preceding year;
(ii) Make-Up LNG relating to a Take-or-Pay Quantity paid
for in respect of the immediately preceding year; or
(iii) Restoration Quantities relating to a Force Majeure
Deficiency arising in respect of the immediately
preceding year;
provided that the requested LNG is available and such request
is received by Seller not later than January 15 of the year
to which such Annual Program relates.
12.2 Ninety-Day Schedules
Not later than the fifteenth (15th) day of each calendar month,
Seller shall, after discussion with each Buyer, deliver to each Buyer
a three-month forward plan of loadings (the "Ninety-Day Schedule"),
which follows the applicable Annual Program (or most current draft
thereof) as nearly as practicable and sets forth the projected dates
of loadings for each of the next three (3) calendar months. Each
Ninety-Day Schedule shall reflect all adjustments, if any,
necessitated by deviation from prior Ninety-Day Schedules so as to
maintain as far as practicable the loadings forecast in the Annual
Program. Both parties shall cooperate to facilitate smooth
performance of the Ninety-Day Schedule. After consultation with
Buyers, Seller shall revise the Ninety- Day Schedule when appropriate
to meet operational requirements with the overall objective of
fulfilling the Annual Program as far as practicable, taking into
account any requests of Buyers for adjustments.
<PAGE> 44
ARTICLE 13 - MEASUREMENTS AND TESTS
13.1 Parties to Supply Devices
Buyers shall supply, operate and maintain, or cause to be supplied,
operated and maintained, suitable gauging devices, density, pressure
and temperature measuring devices, and any other measurement or
testing devices for the LNG tanks of the LNG Tankers, which are
incorporated in the structure of LNG Tankers or customarily
maintained on shipboard.
Seller shall supply, operate and maintain, or cause to be supplied,
operated and maintained, devices required for collecting samples and
for determining quality and composition of the LNG and any other
measurement or testing devices which are necessary to perform the
measurement and testing required hereunder at the Badak Facility.
13.2 Selection of Devices
All devices provided for in this Article 13 shall be chosen by mutual
agreement of the parties and shall be such that at the time of
selection are the most accurate and reliable devices in their
practical application. The required degree of accuracy of such
devices selected shall be mutually agreed upon and verified by Buyers
and Seller in advance of their use, and at the request of either
Buyer or Seller such degree of accuracy shall be verified by an
independent surveyor mutually agreed upon by such Buyer and Seller.
13.3 Units of Measurement and Calibration
The parties will cooperate closely in the design, selection and
acquisition of devices to be used for measurements and tests under
this Article 13 in order that, to the maximum extent possible, all
measurements and tests may be conducted either in American units of
measurement or in metric units of measurement. In the event that it
becomes necessary to make measurements and tests using a new system
of units of measurement, the parties shall establish mutually
agreeable conversion tables, or, if they are unable to agree, such
tables may be established by the procedures provided for resolution
of disputes on measurement and testing in Section 13.11. Measurement
devices shall be calibrated as follows:
<PAGE> 45
<TABLE>
<S> <C> <C>
Measurement American Units Metric Units
Volume Cubic feet Cubic Meters
Temperature Degress Fahrenheit Degrees Centrigade
Pressure Pounds per square Kilograms per square
inch or inches of centimeter or
mercury milimeters of mercury
Length Feet Meters
Weight Pounds Kilograms
Density Pounds per cubic feet Kilograms per Cubic
Meters
</TABLE>
13.4 Tank Gauge Tables of LNG Tankers
Buyers shall provide Seller, or cause Seller to be provided, with a
certified copy of tank gauge tables for each tank of each LNG Tanker
verified by a competent impartial authority or authorities mutually
agreed upon by the parties. Such tables shall include correction
tables for list, trim, tank construction and any other items
requiring such tables for accuracy of gauging. Seller and Buyers
shall each have the right to have representatives present at the time
each LNG tank on each LNG Tanker is volumetrically calibrated. If the
LNG tanks of any LNG Tanker suffer distortion of such nature as to
cause a prudent expert reasonably to question the validity of the
tank gauge tables described herein (or any subsequent calibration
provided for herein), any Buyer or Seller may require recalibration
of such LNG tanks during any period when the LNG Tanker is out of
service for inspection and/or repairs. Upon recalibration of the LNG
tanks of the LNG Tankers, the same procedures used to provide the
original tank gauge tables will be used to provide revised tank gauge
tables based upon the recalibration data. The calibration of tanks
provided for in this Section 13.4 shall constitute the only
calibration required for purposes of this Contract.
13.5 Gauging and Measuring LNG Volumes Delivered
Volumes of LNG delivered pursuant to this Contract shall be
determined by gauging the LNG in the tanks of the LNG Tankers before
and after loading.
Gauging the liquid in the tanks of the LNG Tankers and measuring of
liquid temperature, vapor temperature, vapor pressure and liquid
density in each LNG tank, trim and list of the LNG Tankers, and
atmospheric pressure shall be performed, or be caused to be
performed, by the Buyer purchasing the LNG, before and after loading.
<PAGE> 46
The first gauging and measurements shall be made immediately before
the commencement of loading. The second gauging and measurements
shall take place immediately after the completion of loading.
Copies of gauging and measurement records shall be furnished to
Seller.
A. Gauging the Liquid Level of LNG
The level of the LNG in each LNG tank of the LNG Tanker shall
be gauged by means of the gauging device installed in the LNG
Tanker for that purpose. The level of the LNG in each tank
shall be logged or printed.
B. Determination of Temperature
The temperature of the LNG and of the vapor space in each
cargo tank shall be measured by means of a sufficient number
of properly located temperature measuring devices to permit
the determination of average temperature. Temperatures shall
be logged or printed.
C. Determination of Pressure
The pressure of the vapor in each LNG tank shall be
determined by means of pressure measuring devices installed
in each LNG tank of the LNG Tankers. The atmospheric pressure
shall be determined by readings from the standard barometer
installed in the LNG Tankers.
D. Determination of Density
Density of the LNG shall be computed by Seller or, if
mutually agreed, measured. Initially, the density of the LNG
will be computed by the method described in Schedule A.
Should any improved data, method of calculation or direct
measurement device become available which is acceptable to
both Buyers and Seller, such improved data, method or device
shall then be used. If density is determined by measurements,
the results shall be logged or printed.
13.6 Samples for Quality Analysis
Representative samples of the LNG delivered shall be obtained, or be
caused to be obtained, in triplicate by Seller during the time of
loading. The three (3) samples shall be taken from an appropriate
point on Seller's loading line as close as possible to the loading
flanges and collected in the gaseous state using the continuous
gasification/collection method agreed by Buyers and Seller.
<PAGE> 47
In addition periodic samples shall be obtained during loading. Should
Seller determine that it is necessary to utilize periodic samples,
the composition of the LNG delivered to each LNG Tanker shall be the
arithmetic average of the results obtained by analysis of such
samples. The method and devices for sampling and the quantity of the
samples to be withdrawn shall be determined by agreement between
Buyers and Seller to provide for taking representative and adequate
samples of the LNG delivered.
The samples obtained shall be distributed as follows:
First sample - for use of Seller.
Second sample - for use of Buyer receiving the LNG
shipment.
Third sample - for retention by Seller for the
agreed period, not to exceed
twenty-five (25) days, during which
period any dispute as to the
accuracy of any analysis shall be
raised, in which case the sample
shall be further retained until
such Buyer and Seller agree to
retain it no longer.
13.7 Quality Analysis
The samples provided for in Section 13.6 shall be analyzed, or be
caused to be analyzed, by Seller to determine the molar fraction of
the hydrocarbon and other components in the sample by gas
chromatography using a mutually agreed method in accordance with
"G.P.A. Standard 2261, Analysis for Natural Gas and Similar Gaseous
Mixtures by Gas Chromatography", published by G.P.A., current as of
1990 or as otherwise mutually agreed upon. If better standards for
analysis are subsequently adopted by G.P.A. or other recognized
competent impartial authority, upon mutual agreement of Buyers and
Seller, they shall be substituted for the standard then in use, but
such substitution shall not take place retroactively. A calibration
of the chromatograph or other analytical instrument used shall be
performed by Seller immediately prior to the analysis of the sample
of LNG delivered. Seller shall give advance notice to Buyers of the
time Seller intends to conduct a calibration thereof, and Buyers
shall have the right to have a representative present at each such
calibration; provided, however, Seller will not be obligated to defer
or reschedule any calibration in order to permit the representative
of Buyers to be present.
<PAGE> 48
The sample shall be analyzed, or be caused to be analyzed, by Seller
to determine the concentrations of hydrogen sulfide (H2S) and total
sulfur content referred to in Section 11.2 using the methods
described in Schedule A.
13.8 Operating Procedures
Prior to conducting operations for measurement, gauging and analysis
provided in Sections 13.5, 13.6 and 13.7, the party responsible for
such operations shall notify the appropriate representatives of the
other party, allowing such representatives reasonable opportunity to
be present for all operations and computations; however, the absence
of the other party's representative after notification and
opportunity to attend shall not prevent any operations and
computations from being performed. At the request of either party,
any measurement, gauging and analysis provided for in Sections 13.5,
13.6 and 13.7 shall be witnessed and verified by an independent
surveyor mutually agreed upon by the Buyer and Seller. The results of
such surveyor's verifications shall be made available promptly to
each party. All records of measurement and the computation results
shall be preserved and available to both parties for a period of not
less than three (3) years after such measurement and computation.
13.9 BTU Quantities Sold
The quantity of BTU's sold shall be calculated by Seller following
the procedures described in this Section 13.9 and shall be verified
by an independent surveyor mutually agreed upon by Seller and Buyers.
A. Determination of Gross Heating Value
The Gross Heating Value of the samples of the LNG shall be
determined by computation, in accordance with the method
described in Schedule A, on the basis of the molecular
composition determined pursuant to Section 13.7 and of the
molecular weights and heating values described in "G.P.A.
Publication 2145" published by G.P.A., current at the time of
computation.
If better constants or improved methods for determination of
heating value are subsequently adopted by G.P.A. or other
recognized competent impartial authority, they shall, upon
mutual agreement of Seller and Buyers, be substituted
therefor, but not retroactively. The Gross Heating Value of
the representative sample shall be the conclusive Gross
Heating Value for the purpose of determining quantities of
BTU's sold.
<PAGE> 49
B. Determination of Volume of LNG Loaded
The LNG volume in the tanks of the LNG Tanker before and after
loading shall be determined by gauging as provided in Section 13.5 on
the basis of the tank gauge tables provided for in Section 13.4. The
volume of LNG remaining in the tanks of the LNG Tanker before loading
shall then be subtracted from the volume after loading and the
resulting volume shall be taken as the volume of the LNG delivered to
the LNG Tanker.
If failure of gauging and measuring devices of an LNG Tanker should
make it impossible to determine the LNG volume, the volume of LNG
delivered shall be determined by gauging the liquid level in Seller's
onshore LNG storage tanks immediately before and after loading the
LNG Tanker, and such volume shall be reduced by subtracting an
estimated LNG volume, agreed upon by the parties, for boil-off from
such tanks during the loading of such LNG Tanker. Seller shall
provide Buyers, or cause the Buyers to be provided with, a certified
copy of tank gauge tables for each onshore LNG tank which is to be
used for this purpose, such tables to be verified by a competent
impartial authority.
C. Determination of BTU Quantities Sold
The quantities of BTU's sold shall be computed by Seller by means of
the following formula:
Q = V x D x P
where: Q represents the quantity of the LNG sold in BTU's.
V represents the volume of the LNG loaded, stated in
Cubic Meters, determined as provided in Section 13.9
B.
D represents the density of the LNG loaded, stated in
kilograms per Cubic Meter, determined as provided in
Section 13.5 D.
P represents the Gross Heating Value of the LNG
loaded, stated in BTU's per kilogram.
Physical constants, calculation procedures and examples of BTU
determination are provided in Schedule A.
<PAGE> 50
13.10 Verification of Accuracy and Correction for Error Accuracy of devices
used shall be tested and verified at the request of either party,
including the request by a party to verify accuracy of its own
devices. Each party shall have the right to inspect at any time the
measurement devices installed by the other party, provided that the
other party be notified in advance. Testing shall be performed only
when both parties are represented, or have received adequate advance
notice thereof, using methods recommended by the manufacturer or any
other method agreed to by Seller and Buyers. At the request of any
party hereto, any test shall be witnessed and verified by an
independent surveyor mutually agreed upon by Buyers and Seller.
Permissible tolerances shall be defined in Schedule A. Inaccuracy of
a device exceeding the permissible tolerances shall require
correction of previous recordings, and computations made on the basis
of those recordings, to zero error with respect to any period which
is definitely known or agreed upon by the parties, as well as
adjustment of the device. In the event that the period of error is
neither known nor agreed upon, corrections shall be made for each
delivery made during the last half of the period since the date of
the most recent calibration of the inaccurate device. However, the
provisions of this Section 13.10 shall not be applied to require the
modification of any invoice that has become final pursuant to Section
10.6.
13.11 Disputes
In the event of any dispute concerning the subject matter of this
Article 13, including, but not limited to, disputes over selection of
the type or the accuracy of measuring devices, their calibration, the
result of measurement, sampling, analysis, computation or method of
calculation, such dispute shall be submitted to a competent impartial
authority mutually agreed upon by the parties or, if such authority
cannot be agreed upon within thirty (30) days of request by either
party, such dispute shall be decided by arbitration pursuant to
Article 16. All decisions of an authority acting under this Section
13.11 shall be binding on the parties. Expenses incurred in
connection with the services of such authority shall be shared
equally by the parties.
13.12 Costs and Expenses of Test and Verification
All costs and expenses for testing and verifying Seller's measurement
devices as provided for in this Article 13 shall be borne by Seller,
and all costs and expenses for testing and verifying Buyers'
measurement devices shall be borne by Buyers. The fees and charges of
independent surveyors for measurements and calculations as provided
for in Sections 13.8 and 13.9 shall be borne equally by Seller and
Buyer. When the services of independent surveyors are required and
selected by mutual agreement pursuant to Section 13.10, then the fees
and charges of such surveyors shall be borne equally by Seller and
Buyers.
<PAGE> 51
ARTICLE 14 - DUTIES AND TAXES
Seller shall pay (or reimburse Buyers for any such payments made by them) all
taxes, royalties, duties or other imposts levied or imposed by the Indonesian
Government, any subdivision thereof or any other governmental authority in
Indonesia on the sale or export of LNG.
<PAGE> 52
ARTICLE 15 - FORCE MAJEURE
15.1 Events of Force Majeure
Neither Seller nor any Buyer shall be liable for any delay or failure
in performance hereunder if and to the extent such delay or failure
in performance directly results from any of the following:
(a) Other than LNG Tankers
(i) Fire, flood, atmospheric disturbance, lightning,
storm, typhoon, tornado, earthquake, landslide, soil
erosion, subsidence, washout or epidemic;
(ii) War, riot, civil war, blockade, insurrection, act of
public enemies or civil disturbance;
(iii) Strike, lockout or other industrial disturbance;
(iv) Serious accidental damage to or serious failure of
Seller's Facilities, unless such damage or failure
is the result of gross negligence on the part of
Seller's management;
(v) Serious accidental damage to or serious failure of a
Buyer's Facilities, unless such damage or failure is
the result of gross negligence on the part of such
Buyer's management;
(vi) The Proved Remaining Recoverable Reserves of Natural
Gas in the Gas Supply Area expressed in the then
most recent Certificate referred to in Section
3.2(a) which can be economically produced have been
fully depleted; or
(vii) Act of government that directly affects the ability
of a party to perform any obligation hereunder other
than the obligation to remit payments as provided in
Section 10.4 on account of LNG delivered and taken
or not taken but required to be paid for under this
Contract.
(b) As to LNG Tankers
(i) The removal of an LNG Tanker from service due to
loss, serious accidental damage or other serious
failure, or other unavailability of an LNG Tanker,
unless such loss, damage, failure or unavailability
is the result of gross negligence on the part of
Buyers;
<PAGE> 53
(ii) Fire, flood, atmospheric disturbance, lightning,
storm, typhoon, tornado or epidemic;
(iii) War, riot, civil war, blockade, insurrection, act of
public enemies or civil disturbance;
(iv) Strike, lockout or other industrial disturbance
occurring aboard an LNG Tanker or at a port or other
facility at which such an LNG Tanker calls; or
(v) Act of government.
15.2 Notice; Resumption of Normal Performance
(a) Immediately upon the occurrence of an event of force majeure
that gives a party warning that the event may delay or
prevent the performance by Seller or any Buyer of any of its
obligations hereunder, the party affected shall give notice
thereof to the other parties describing such event and
stating the obligations the performance of which are, or are
expected to be, delayed or prevented, and (either in the
original or in supplemental notices) stating:
(i) The estimated period during which performance may be
suspended or reduced, including, to the extent known
or ascertainable, the estimated extent of such
reduction in performance; and
(ii) The particulars of the program to be implemented to
ensure full resumption of normal performance
hereunder.
(b) In order to ensure resumption of normal performance of this
Contract within the shortest practicable time, the party
affected by an event of force majeure shall take all measures
to this end which are reasonable in the circumstances, taking
into account the consequences resulting from such event of
force majeure. Prior to resumption of normal performance, the
parties shall continue to perform their obligations under
this Contract to the extent not prevented by such event.
<PAGE> 54
15.3 Settlement of Industrial Disturbances
Settlement of strikes, lockouts or other industrial disturbances
shall be entirely within the discretion of the party experiencing
such situations and nothing herein shall require such party to settle
industrial disputes by yielding to demands made on it when it
considers such action inadvisable.
<PAGE> 55
ARTICLE 16 - ARBITRATION
All disputes arising between any Buyer or Buyers, on the one hand, and Seller,
on the other hand, relating to this Contract or the interpretation or
performance hereof shall be finally settled by arbitration conducted in
accordance with the Rules of Arbitration of the International Chamber of
Commerce, effective at the time, by three (3) arbitrators appointed in
accordance with such Rules. Arbitration shall be conducted in the English
language and shall be held at Paris, France, unless another location is
selected by mutual agreement of the parties concerned. The award rendered by
the arbitrators shall be final and binding upon the parties concerned.
<PAGE> 56
ARTICLE 17 - APPLICABLE LAW
This Contract shall be governed by and interpreted in accordance with the laws
of the State of New York, United States of America. The parties agree that the
United Nations Convention on Contracts for the International Sale of Goods and
the Convention on the Limitation Period in the International Sale of Goods
shall not apply to this Contract and the respective rights and obligations of
the parties hereunder.
<PAGE> 57
ARTICLE 18 - BUYERS' COORDINATOR AND REPRESENTATIVE
Buyers will from time to time designate a Buyers' Coordinator and a Buyers'
Representative to act on behalf of each Buyer in performing the following:
A. Coordination among each of the Buyers, and between Seller and Buyer
or Buyers, and the handling of communications between Seller and
Buyer or Buyers in connection with performance of this Contract, in
particular the exercise of Allowances pursuant to Section 7.3(d); and
B. Implementation of various operations of each Buyer or of Buyers which
are necessary in connection with purchasing and receiving of LNG
hereunder.
Buyers shall notify Seller the name and address of the entities to act as
Buyers' Coordinator and Buyers' Representative and shall specify the duties to
be performed by each such entity. Buyers have notified Seller that Japan
Indonesia LNG Co., Ltd. is presently acting as Buyers' Coordinator, and that
P.T. Jasa Enersi Pratama Nusantara is presently acting as Buyers'
Representative.
Seller shall be entitled to accept and rely upon any communication received
from Buyers' Coordinator or Buyers' Representative as if received directly from
one or more of Buyers, and to give communications to Buyers' Coordinator or
Buyers' Representative with the same effect as if given directly to a Buyer or
Buyers. No act of, or authorization to, Buyers' Coordinator or Buyers'
Representative shall relieve any Buyer from performance of any obligation or
payment of any liability of such Buyer hereunder, each Buyer remaining
primarily liable therefor at all times.
<PAGE> 58
ARTICLE 19 - CONFIDENTIALITY
No party to this Contract shall use or communicate to third parties the
contents of this Contract or other confidential information or documents which
may come into the possession of such party in connection with the performance
of this Contract without the prior agreement of the party or parties to which
such information or documents are confidential. This restriction shall not
apply to the contents of this Contract, or information or documents, which:
(i) have fallen into the public domain otherwise than through the
act or failure to act of the party that has obtained them; or
(ii) are communicated to:
(A) any of Seller's Suppliers, or any Affiliate (as
defined below), with the obligation of the receiving
person to maintain confidentiality;
(B) persons participating in the implementation of this
project, such as Buyers' Transporter, Buyers'
Coordinator, Buyers' Representative, legal counsel,
accountants, other professional, business or
technical consultants and advisers, underwriters or
lenders, with the obligation of the receiving
persons to maintain confidentiality; or
(C) any governmental agency of the Republic of Indonesia
or Japan, or having jurisdiction over any of
Seller's Suppliers or any Affiliate or Buyers'
Transporter, provided that such agency has authority
to require such disclosure, and that such disclosure
is made in accordance with that authority.
As used before, the term "Affiliate" means a company that controls, is
controlled by, or is under common control with, a party to this Contract or any
of Seller's Suppliers.
<PAGE> 59
ARTICLE 20 - NOTICES
All notices and other communications for purposes of this Contract shall be in
writing, which shall include transmission by telex, facsimile or telegraph,
except that notices given from LNG Tankers at sea may be by radio. Notices and
communications shall be directed as follows:
A. To Seller at the following mail address :
PERUSAHAAN PERTAMBANGAN MINYAK DAN GAS
BUMI NEGARA (PERTAMINA)
Attention : General Manager, Gas Marketing Department
P.O. Box 12/JKT
Jalan Merdeka Timur No. 1A,
Jakarta Pusat, Indonesia
And at the following telegraph, telex and facsimile addresses:
Telegraph: Telex:
PERTAMINA PERTAMINA
JAKARTA, INDONESIA 44302 or 44152
Attention : General Manager, JAKARTA,
Gas Marketing INDONESIA
Department
Facsimile: 62-21-345-8312
B. To Buyers at the following mail, telegraph, telex and facsimile
addresses :
CHUBU ELECTRIC POWER CO., INC.
(Mail and telegraph address) Attention: Fuels Department
1, Toshin-cho, Higashi-ku,
Nagoya, 461-91 Japan
(Telex address) 4444405 CHUDEN J
(Facsimile address) 81-52-951-6025
THE KANSAI ELECTRIC POWER CO., INC.
(Mail and telegraph address) Attention: LNG Group, Office of
Purchasing 3-22, Nakanoshima
3-chome, Kita-ku, Osaka, 530-70
Japan
(Telex address) 5248320 KEPCO J
(Facsimile address) 81-6-441-0283
<PAGE> 60
OSAKA GAS CO., LTD.
(Mail and telegraph address) Attention: Gas Resources Department
1-2, Hiranomachi 4-chome, Chuo-ku,
Osaka, 541 Japan
(Telex address) 5225275DAIGAS J
(Facsimile address) 81-6-222-2044
TOHO GAS CO., LTD.
(Mail and telegraph address) Attention: Raw Materials Department
19-18, Sakurada-cho, Atsuta-ku,
Nagoya, 456 Japan
(Telex address) 4477651 TOHOGS J
(Facsimile address) 81-52-871-6967
The parties may designate additional addresses for particular communications as
required from time to time, and may change any addresses, by notice given
thirty (30) days in advance of such additions or changes. Immediately upon
receiving communications by telex, facsimile, telegraph or radio, a party shall
acknowledge receipt by the same means, and may request a repeat transmittal of
the entire communication or confirmation of particular matters. If the sender
receives no acknowledgement of receipt within twenty-four (24) hours, or
receives a request for repeat transmittal or confirmation, said party shall
repeat the transmittal or answer the particular request.
<PAGE> 61
ARTICLE 21 - ASSIGNMENT
Neither this Contract nor any rights or obligations hereunder may be assigned
by any Buyer without the prior written consent of Seller, or by Seller without
the prior written consent of each Buyer. Any request by a Buyer for Seller's
consent to an assignment shall be accompanied by the written consent of each
other Buyer to the proposed assignment. Any purported assignment without the
aforesaid consent or consents shall be null and void.
<PAGE> 62
ARTICLE 22 - AMENDMENTS
This Contract may not be amended, modified, varied or supplemented except by an
instrument in writing signed by Seller and Buyers.
Performance of any condition or obligation to be performed hereunder shall not
be deemed to have been waived or postponed except by an instrument in writing
signed by the party who is claimed to have granted such waiver or postponement.
<PAGE> 63
ARTICLE 23 - SEVERALTY
This Contract shall be binding upon each Buyer in accordance with its terms.
The liabilities of Buyers under this Contract are several and not joint, and
each Buyer shall be liable only for performance of the obligations of such
Buyer as provided in this Contract.
<PAGE> 64
ARTICLE 24 - DETAILS OF PERFORMANCE
Details necessary for performance of this Contract shall be mutually agreed
upon by Seller and each Buyer separately or, when necessary and desirable, by
Seller and Buyers on a coordinated and mutually agreeable basis.
<PAGE> 65
ARTICLE 25 - SCOPE
This Contract constitutes the entire agreement between the parties relating to
the subject matter hereof and supersedes and replaces any provisions on the
same subject contained in any other agreement between the parties, whether
written or oral, prior to the date of the original execution hereof.
Subsequent to the date of original execution of this Contract, various
agreements, manuals, procedures and details of performance relating to the
interpretation or implementation of the First A/R, or covering matters related
thereto, have been agreed between Seller and Buyers ("Ancillary Agreements").
It is agreed that no Ancillary Agreement or portion thereof, to the extent it
is in effect and capable of performance, shall be annulled, terminated or
revoked by reason of the execution of this Second A/R, except that:
(i) to the extent that there is any conflict between such
Ancillary Agreements and any specific amendment to the
Contract incorporated in this Second A/R, such specific
amendment shall prevail;
(ii) the Ancillary Agreements (or identified portions thereof)
that were superseded by the First A/R (Section 25(ii)) shall
continue to be without effect; and
(iii) the 1981 Extension MOA shall be terminated.
<PAGE> 66
ARTICLE 26 - COUNTERPARTS
This Second A/R is executed in five (5) identical counterparts, each of which
shall have the force and dignity of an original, and all of which shall
constitute but one and the same Second A/R.
<PAGE> 67
ARTICLE 27 - EFFECTIVE DATE AND APPLICABILITY
This Second A/R shall be effective as of the date of execution stated below.
Notwithstanding the foregoing sentence, the provisions of the First A/R (except
Article 6) shall continue to apply and shall take precedence over this Second
A/R until April 1, 2003.
IN WITNESS WHEREOF, each of the parties has caused this Second A/R to be duly
executed and signed by its duly authorized officer as of August 3, 1995.
SELLER : BUYERS :
PERUSAHAAN PERTAMBANGAN CHUBU ELECTRIC POWER CO., INC.
MINYAK DAN GAS BUMI NEGARA
(PERTAMINA)
By: /s/ F. ABDA'OE By: /s/ HIROJI OTA
------------------------- -------------------------
Name: F. Abda'oe Name: Hiroji Ota
------------------------- -------------------------
Title: President Director Title: President and C.E.O.
------------------------- -------------------------
THE KANSAI ELECTRIC POWER CO.,
INC.
By: /s/ YOSHIHISA AKIYAMA
-------------------------
Name: Yohishisa Akiyama
-------------------------
Title: President and Director
-------------------------
WITNESSES :
JAPAN INDONESIA LNG CO., LTD. OSAKA GAS CO., LTD.
By: /s/ MASUO SHIBATA By: /s/ SHIN-ICHIRO RYOKI
------------------------- -------------------------
Name: Masuo Shibata Name: Shin-ichiro Ryoki
------------------------- -------------------------
Title: President and Director Title: President
------------------------- -------------------------
NISSHO IWAI CORPORATION TOHO GAS CO., LTD.
By: /s/ AKIRA NISHIO By: /s/ SADAHIKO SHIMIZU
------------------------- -------------------------
Name: Akira Nishio Name: Sadahiko Shimizu
------------------------- -------------------------
Title: President Title: President
------------------------- -------------------------
<PAGE> 68
SIDE LETTER TO SECOND AMENDED AND RESTATED 1981 BADAK
LNG SALES CONTRACT August 3, 1995
CHUBU ELECTRIC POWER CO., INC.
THE KANSAI ELECTRIC POWER CO., INC.
OSAKA GAS CO., LTD.
TOHO GAS CO., LTD.
Gentlemen,
This Side Letter relates to the Second Amended and Restated 1981 Badak LNG
Sales Contract ("Second A/R") of even date herewith (terms defined therein
having the same meanings when used in this Side Letter).
A. HNS CONVENTION
The International Maritime Organization is developing an International
Convention on Liability and Compensation for Damage in Connection with the
Carriage of Hazardous and Noxious Substances by Sea ("HNS Convention"). If it
becomes likely that the HNS Convention will apply to shipments of LNG under the
Second A/R, then Seller and Buyers shall engage in a process of mutual review
and consultation in order to determine how to allocate any payments Seller is
required to make under the HNS Convention relating to the Fixed Quantities.
B. OMNIBUS AGREEMENT AND WAIVER AGREEMENT
Conditions of Use for Bontang, Selatan LNG Marine Terminal
("Conditions of Use") will be signed by the master of each LNG Tanker before
using the Loading Port facilities. The Conditions of Use shall be modified by
an Omnibus Agreement between Seller, Seller's Suppliers and Buyers' Transporter
(the "Omnibus Agreement") and a Waiver Agreement between Seller, Seller's
Suppliers, Buyers' Transporter and Buyers (the "Waiver Agreement") which
(subject to the paragraph below) are in the same form and substance as hitherto
executed in connection with the use of the Loading Port by other LNG vessels.
If Seller and Buyers agree to modify the existing Omnibus Agreement, Seller
shall sign and cause Seller's Suppliers to sign such modified Omnibus Agreement
and Buyers shall cause Buyers' Transporter to sign such modified Omnibus
Agreement. In addition, if Seller and Buyers agree to modify the existing
Waiver Agreement, Seller shall sign and cause Seller's Suppliers to sign such
modified Waiver Agreement and Buyers shall sign and cause Buyers' Transporter
to sign such modified Waiver Agreement.
Seller believes that changing circumstances and increasing values at
the Badak Facility necessitate making changes to the Omnibus Agreement
regarding the required protection and indemnity insurance coverage in respect
of the LNG Tankers ("P&I Cover"). Seller and Buyers shall therefore engage as
soon as possible in a process of mutual review and consultation in order to
determine whether the P&I Cover should be increased to U.S.$300,000,000, as
proposed by Seller.
<PAGE> 69
C. DEFINITION OF BUSINESS DAY IN JAPAN
Seller and Buyers have not reached a conclusion regarding whether
December 31 should be considered a Business Day in Japan. Buyers are not able
to make payment to Seller on December 31 through a bank in Japan since December
31 is, by Japanese Government order, a non-banking day in Japan. However,
Seller believes the treatment of December 31 as a non-business day would cause
Seller to incur substantial financial losses and is not justified by the
difficulties faced by Buyers.
Seller and Buyers are willing to engage in a process of mutual review
and consultation on the exclusion of December 31 as a Business Day in Japan in
the context of considering such a change for all of Seller's sales contracts
with Japanese buyers.
D. PRICE TRANSITION
With regard to the transition from the price under the First A/R and
the Second A/R, Seller and Buyers have agreed to the following:
(i) The provisions regarding Contract Sales Price set forth in
Article 8 of the First A/R shall apply to each Buyer
individually until such Buyer's Fixed Quantities under the
First A/R are sold and delivered ("FQ Cut-Off Point"). For the
purpose of determining the FQ Cut-Off Point for each Buyer,
any outstanding Quantity Deficiency, Force Majeure Deficiency
and Allowance shall be added to the Fixed Quantities delivered
under the First A/R.
(ii) During the period from January 1, 2000 until the FQ Cut-Off
Point, the Floor Price (as defined in the First A/R) shall
apply and shall be calculated as if the Amended and Restated
1973 LNG Sales Contract dated January 1, 1990 were still in
effect.
(iii) The provisions regarding Contract Sales Price set forth in
Article 8 of the Second A/R shall apply individually to the
Fixed Quantities of each Buyer sold and delivered after such
Buyer's FQ Cut-Off Point and to all Make-Up LNG, Make-Good LNG
and Restoration Quantities delivered after such FQ Cut-Off
Point.
(iv) Seller and Buyers recognize the possibility that the
application of the above may result in cargo deliveries which
contain quantities at the First A/R Contract Sales Price and
quantities at the Second A/R Contract Sales Price.
(v) Seller and Buyers shall agree such implementation procedures
as may be required to give effect to the above.
<PAGE> 70
E. PRICING
Article 8 of the Second A/R refers to realized export prices (except
premiums and except prices for spot sales) of field classifications of
Indonesian crude oils being sold and exported. The parties acknowledge that as
of the effective date of the Second A/R, the Indonesian Crude Price (ICP)
system establishes such realized export prices.
If at any time in the opinion of Seller or Buyers, based on their
independent studies, the prices of the field classifications used by Seller to
determine "A" in the formula in Section 8.2(a) are materially different from
the realized export prices, such party shall so notify the other stating the
basis for such opinion, and the parties shall consult promptly and jointly
review the matter with a view to determining whether such difference exists
and, if so, to establishing an alternative basis, to be adopted by Seller, for
determining (for the purposes of the Second A/R) such realized export prices
(except premiums and except prices for spot sales).
In such event the parties shall continue to administer and perform the
provisions of the Second A/R, and to determine the Contract Sales Price and
submit and pay invoices, on the basis provided for in the Second A/R, until the
parties shall have completed such joint review.
If, upon completion of such joint review, it is determined that such
difference exists, then Seller shall promptly take all measures to ensure
proper administration of the Second A/R at all times, including any necessary
recalculation of the Contract Sales Price.
F. EXCESS CAPACITY
Seller confirms that it places great importance on the mutual trust
and cooperation that exists with Buyers, and that no changes effected by the
said amendment and restatement are intended to adversely effect the
relationship between the parties. Seller also fully appreciates the marketing
opportunities for the excess capacity of its LNG facilities provided by Buyers
and will continue to pursue such opportunities in the future.
It is Seller's policy to retain the right to dispose of the excess
capacity of its LNG facilities to such purchasers and upon such terms as it may
elect. Seller is therefore unable to grant any general reservations of its
excess capacity.
However, in view of the long term business relationship between Seller
and Buyers, Seller agrees that once a Buyer offers in writing to purchase a
specified quantity of LNG on terms to be agreed, then and to the extent Seller
determines that it has excess LNG production capacity and (if applicable)
shipping capacity available, then Seller will give preferential consideration
to such offer over future offers from other potential purchasers for a
reasonable period while good faith negotiations are being conducted with such
Buyer.
<PAGE> 71
G. SIDE LETTER TO BADAK LNG SALES CONTRACT
With regard to the Amended and Restated Side Letter to Badak LNG Sales
Contract, dated January 1, 1990, between Seller and Buyers (a copy of which is
attached hereto), it is hereby agreed that such Side Letter shall continue in
full and force effect and shall apply mutatis mutandis to the Second A/R.
This Side Letter shall be effective as of the date of execution, except the
provisions of paragraphs E, F and G above shall be effective as of and from
April 1, 2003. This Side Letter supersedes as of April 1, 2003 any prior
written instrument between the parties with respect to the subjects herein
mentioned .
Very truly yours,
PERUSAHAAN PERTAMBANGAN
MINYAK DAN GAS BUMI
NEGARA (PERTAMINA)
By: /s/ F. ABDA'OE
-----------------------------
Name: F. Abda'oe
-----------------------
Title: President and Director
-----------------------
AGREED AND ACCEPTED
CHUBU ELECTRIC POWER CO., INC. THE KANSAI ELECTRIC POWER CO., INC.
By: /s/ HIROJI OTA By: /s/ YOSHIHISA AKIYAMA
------------------------- -----------------------------
Name: Niroji Ota Name: Yoshihisa Akiyama
------------------------- -----------------------
Title: President and C.E.O. Title: President and Director
------------------------- -----------------------
OSAKA GAS CO., LTD. TOHO GAS CO., LTD.
By: /s/ SHIN-ICHIRO RYOKI By: /s/ SADAHIKO SHIMIZU
------------------------- -------------------------
Name: Shin-ichiro Ryoki Name: Sadahiko Shimzu
------------------------- -------------------------
Title: President Title: President
------------------------- -------------------------
<PAGE> 72
SECOND AMENDED AND RESTATED 1981 BADAK LNG
SALES CONTRACT
The following describes Schedule A to the Second Amended and Restated 1981 LNG
Sales Contract, which is omitted herein, but will be furnished upon request:
Schedule A - Testing and Methods
Part I - BTU Quantity Determination (setting forth a table of physical
constants and the formulae for LNG density determination, gross
heating value calculation and total BTU's delivered calculation)
Table I - Example of LNG Density Calculation
Table II - Molar Volumes of Individual Components
Table III - Correction C for Volume Reduction of Mixture
Table IV - Example of Gross Heating Value Calculation
Part II - Quality Determinations
Part III - Maximum Permissible Tolerances
Part IV - Rounding
In addition, Side Letter and Exhibit A thereto, dated January 1, 1990
(regarding certain transportation matters), and Side Letters, dated August 3,
1995 (regarding deliverability of LNG from the Badak Facility and LNG Tankers),
to the Second Amended and Restated 1981 Badak LNG Sales Contract.
<PAGE> 1
LNG SALES AND PURCHASE CONTRACT
(BADAK V)
BETWEEN
PERUSAHAAN PERTAMBANGAN MINYAK DAN GAS BUMI NEGARA
(PERTAMINA)
AND
KOREA GAS CORPORATION
<PAGE> 2
TABLE OF CONTENTS
<TABLE>
<CAPTION>
PAGE
<S> <C> <C>
ARTICLE 1 - DEFINITIONS
Actual Cubic Foot 1
Affiliate 1
Allowance 1
Allowance Restoration Period 1
Allowed Laytime 1
Annual Program 1
Authorizations and Approvals 1
Arrival Temperature Requirement 2
British Thermal Unit (BTU) 2
Business Day 2
Buyer 2
Buyer's Facilities 2
Buyer's Transporter 2
Certificate 2
Contract 2
Contract Sales Price 2
Coordinated Maintenance Schedule 2
Cubic Meter (CBM) 2
Delivery Point 3
Demurrage 3
ETA 3
Financing 3
Fixed Quantity 3
Fixed Quantity Period 3
Force Majeure 3
Force Majeure Deficiency 3
Gas Supply Area 3
Gross Heating Value 3
Joint Coordinating Committee 3
Liquefied Natural Gas (LNG) 4
LNG Tankers 4
LNG Tanker Cargo Lot 4
Loading Port 4
Loading Port Facilities 4
</TABLE>
<PAGE> 3
<TABLE>
<S> <C> <C>
Make-Good or Made-Good 4
Make-Good LNG 4
Make-Up LNG 4
Natural Gas 4
NBS 4
Ninety-Day Schedule 5
Notice of Readiness 5
Omnibus Agreement 5
Proposed LNG Tankers 5
Proved Remaining Recoverable Reserves 5
Quantity Deficiency 5
Restoration Quantities 5
Round-up Request 5
Seller 5
Seller's Facilities 5
Seller's Gas Supply Obligation 5
Seller's Suppliers 6
Standard Cubic Foot (scf) 6
Statement of Cooling Time 6
Supply Agreement 6
Take-or-Pay Quantity 6
Unloading Port 6
USCPI 7
Used Laytime 7
Waiver Agreement 7
ARTICLE 2 - SALE AND PURCHASE 8
ARTICLE 3 - SOURCES OF SUPPLY 9
3.1 Sources of Supply 9
3.2 Reserves of Natural Gas 9
ARTICLE 4 - LOADING AND TRANSPORTATION 11
4.1 Transportation by Buyer 11
4.2 LNG Tankers 11
</TABLE>
<PAGE> 4
<TABLE>
<S> <C> <C>
4.3 Loading Port Facilities 11
4.4 Loading Port Obligations 12
4.5 Cargo Loading 13
4.6 Notifications of Estimated Time of Arrival 13
at Loading Port
4.7 Berthing Assignments 14
4.8 Vessels Not Ready for Loading 15
4.9 Notice of Readiness 15
4.10 Tank Temperature for Loading and 15
Statement of Cooling Time
4.11 Quantities for Purging and 16
Cooling of Tanks
4.12 Demurrage at Loading Port 16
4.13 Effect of Loading Port Delays, 19
Transportation Costs
ARTICLE 5 - ON-SHORE FACILITIES 21
5.1 Buyer's Facilities 21
5.2 Seller's Facilities 21
ARTICLE 6 - DURATION OF CONTRACT 22
ARTICLE 7 - QUANTITIES 23
7.1 Fixed Quantity 23
7.2 Deliveries 23
7.3 Buyer's Obligation to Take-or-Pay 23
7.4 Force Majeure - Allocation of Deliveries Between 27
Buyer and Other Purchasers
7.5 Make-Up LNG 28
</TABLE>
<PAGE> 5
<TABLE>
<S> <C> <C>
7.6 Force Majeure Deficiency 29
7.7 Allocation for Make-Good LNG, Make-Up LNG and 30
Restoration Quantities
7.8 Priority Order 30
ARTICLE 8 - CONTRACT SALES PRICE 31
8.1 Contract Sales Price 31
8.2 Contract Sales Price and Adjustments Thereto 31
ARTICLE 9 - TRANSFER OF TITLE 33
ARTICLE 10 - INVOICES AND PAYMENT 34
10.1 Invoices and Cargo Documents 34
10.2 Other Invoices 34
10.3 Invoice Due Dates 34
10.4 Payment 35
10.5 Seller's Rights Upon Buyer's 36
Failure to Make Payment
10.6 Disputed Invoices 36
ARTICLE 11 - QUALITY 37
11.1 Gross Heating Value 37
11.2 Components 37
ARTICLE 12 - PROGRAMMING OF DELIVERIES 38
12.1 Annual Programs 38
12.2 Ninety-Day Schedules 38
12.3 Maintenance and Inspection Coordination 39
</TABLE>
<PAGE> 6
<TABLE>
<S> <C> <C>
ARTICLE 13 - MEASUREMENT AND TESTS 40
13.1 Parties to Supply Devices 40
13.2 Selection of Devices 40
13.3 Units of Measurement and Calibration 40
13.4 Tank Gauge Tables of LNG Tankers 41
13.5 Gauging and Measuring 41
LNG Volumes Unloaded
13.6 Samples for Quality Analysis 41
13.7 Quality Analysis 41
13.8 Operating Procedures 42
13.9 BTU Quantity Delivered 42
13.10 Verification of Accuracy and Correction for Error 42
13.11 Costs and Expenses of Tests and Verifications 43
ARTICLE 14 - DUTIES, TAXES AND CHARGES 44
14.1 Indonesian Taxes 44
14.2 Port Charges 44
ARTICLE 15 - FORCE MAJEURE 45
15.1 Events of Force Majeure 45
15.2 Notice, Resumption of Normal Performance 46
15.3 Settlement of Industrial Disturbances 47
ARTICLE 16 - ARBITRATION, REFERENCE TO EXPERT 48
16.1 Arbitration 48
16.2 Disputes of Technical Nature 48
ARTICLE 17 - APPLICABLE LAW 49
</TABLE>
<PAGE> 7
<TABLE>
<S> <C> <C>
ARTICLE 18 - TERMINATION 50
ARTICLE 19 - CONFIDENTIALITY 51
ARTICLE 20 - NOTICES 52
ARTICLE 21 - ASSIGNMENT 54
ARTICLE 22 - AMENDMENT AND WAIVER 55
22.1 Amendment 55
22.2 Waiver 55
ARTICLE 23 - DETAILS OF PERFORMANCE 56
ARTICLE 24 - JOINT COORDINATING COMMITTEE 57
ARTICLE 25 - SCOPE 57
ARTICLE 26 - LANGUAGE OF THE CONTRACT 59
ARTICLE 27 - HEADINGS 60
ARTICLE 28 - COUNTERPARTS 61
SCHEDULE A
</TABLE>
<PAGE> 8
THIS CONTRACT is made this 12th day of August, 1995.
BETWEEN
1. PERUSAHAAN PERTAMBANGAN MINYAK DAN GAS BUMI NEGARA, a State Enterprise
of the Republic of Indonesia, ("PERTAMINA"); and
2. KOREA GAS CORPORATION, a corporation organized under the laws of the
Republic of Korea, ("KGC").
(KGC and PERTAMINA are collectively referred to as the "Parties" and
individually as a "Party".)
In consideration of the mutual agreements contained herein, the Parties hereby
agree as follows:
ARTICLE 1 - DEFINITIONS
The terms or expressions set forth below will have the following meanings when
used in this Contract. Except as otherwise specifically provided, the singular
shall include the plural or vice versa.
Actual Cubic Foot
A volume equal to the volume of a cube whose edge is one foot.
Affiliate
A company that controls, is controlled by, or that is controlled by a company
that controls Buyer, Seller, or any of Seller's Suppliers.
Allowance
As defined in Subarticle 7.3(d).
Allowance Restoration Period
As defined in Subarticle 7.3(d)(iv).
Allowed Laytime
As defined in Subarticle 4.12(a).
Annual Program
As defined in Subarticle 12.1.
Authorizations and Approvals
As defined in Article 18.
1
<PAGE> 9
Arrival Temperature Requirement
As defined in Subarticle 4.10.
British Thermal Unit (BTU)
The amount of heat required to raise the temperature of one avoirdupois pound
of pure water from 59.0 degrees Fahrenheit to 60.0 degrees Fahrenheit at an
absolute pressure of 14.696 pounds per square inch.
Business Day
Every day other than Saturdays, Sundays and national holidays of the country
concerned.
Buyer
Korea Gas Corporation, a corporation organized under the laws of the Republic
of Korea, or the successor in interest to such corporation, or the permitted
assignee of such corporation or such successor in interest.
Buyer's Facilities
As defined in Subarticle 5.1.
Buyer's Transporter
The owner(s) and the operator of an LNG Tanker.
Certificate
As defined in Subarticle 3.2(a).
Contract
This Sales and Purchase Contract including Schedule A annexed hereto and
forming a part hereof, otherwise known as "BADAK V", as it may from time to
time be amended, modified, varied or supplemented in accordance with Article
22.
Contract Sales Price
As defined in Subarticle 8.1.
Coordinated Maintenance Schedule
As defined in Subarticle 12.3.
Cubic Meter (CBM)
A volume equal to the volume of a cube whose edge is one meter.
2
<PAGE> 10
Delivery Point
The point at the Loading Port at which the flange coupling of Seller's loading
line joins the flange coupling of the LNG loading manifold onboard any LNG
Tanker.
Demurrage
As defined in Subarticle 4.12(a).
ETA
As defined in Subarticle 4.6(a).
Financing
As defined in Article 18.
Fixed Quantity
As defined in Subarticle 7.1(a).
Fixed Quantity Period
As defined in Subarticle 7.1(a).
Force Majeure As defined in Subarticle 15.1.
Force Majeure Deficiency
As defined in Subarticle 7.6(a)(i).
Gas Supply Area
The areas in East Kalimantan, Indonesia covered by production sharing contracts
between Seller and Seller's Suppliers and such other nearby contract areas to
each of the foregoing as Seller may designate from time to time.
Gross Heating Value
The quantity of heat, (stated in BTU's), produced by the complete combustion in
air of one cubic foot of anhydrous gas, at a temperature of 60.0 degrees
Fahrenheit and an absolute pressure of 14.696 pounds per square inch, with the
air at the same temperature and pressure as the gas, after cooling the products
of the combustion to the initial temperature of the gas and air, and after
condensation of the water formed by combustion.
Joint Coordinating Committee
As defined in Article 24(a).
3
<PAGE> 11
Liquefied Natural Gas (LNG)
Natural Gas in a liquid state, at or below its boiling point and at a pressure
of approximately one atmosphere.
LNG Tanker
An ocean-going vessel, meeting the requirements of Subarticle 4.2, suitable for
transporting LNG, which is used by Buyer for transportation of LNG delivered
under this Contract.
LNG Tanker Cargo Lot
That quantity of LNG (stated in billions of BTU's) which represents, for
purposes of calculations hereunder, the maximum amount of LNG that can
practicably be loaded onto an LNG Tanker at the Loading Port, taking into
account vessel capacity, port restrictions, heel requirements, actual
deliveries of full LNG cargoes under this Contract and other relevant
considerations.
Loading Port
The port located at and forming a part of Seller's Facilities.
Loading Port Facilities
As defined in Subarticle 4.3(a).
Make-Good or Made-Good
As defined in Subarticle 7.3(d)(iv).
Make-Good LNG
As defined in Subarticle 7.3(d)(iv).
Make-Up LNG
As defined in Subarticle 7.5(a)(i).
MMBTU
One million (1,000,000) BTU's.
Natural Gas
Any hydrocarbon or mixture of hydrocarbons consisting essentially of methane,
other hydrocarbons and non-combustible gases in a gaseous state and which is
extracted from the subsurface of the earth in its natural state, separately or
together with liquid hydrocarbons.
NBS
As defined in Subarticle 16.2.
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<PAGE> 12
Ninety-Day Schedule
As defined in Subarticle 12.2.
Notice of Readiness
As defined in Subarticle 4.9.
Omnibus Agreement
The agreement between Seller, Seller's Suppliers and Buyer's Transporter
modifying the conditions of use of the Loading Port and the Loading Port
Facilities.
Proposed LNG Tankers
As defined in Article 24(a).
Proved Remaining Recoverable Reserves
Reserves which have been proved to a high degree of certainty by reason of
actual completion and/or successful testing of well(s), or in certain cases by
adequate core analyses, and which are defined areally by reasonable geological
interpretation of structure and known continuity of oil or gas saturated
material.
Quantity Deficiency
As defined in Subarticle 7.3(a).
Restoration Quantities
As defined in Subarticle 7.6(a)(i).
Round-Up Request
As defined in Subarticle 7.3(a)(ii).
Seller
Perusahaan Pertambangan Minyak dan Gas Bumi Negara ("PERTAMINA"), a State
Enterprise of the Republic of Indonesia, or the successor in interest of such
enterprise, or the permitted assignee of such enterprise or such successor in
interest.
Seller's Facilities
As defined in Subarticle 5.2.
Seller's Gas Supply Obligation
From time to time on any given date the amount of Natural Gas required to
satisfy the remaining obligations of Seller on such date to supply LNG or
Natural Gas from the Gas Supply Area plus the amount of Natural Gas from the
Gas Supply Area
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<PAGE> 13
required to supply any additional commitment or commitments which Seller
anticipates making.
Seller's Suppliers
In respect of portions of the LNG to be sold hereunder:
(a) Indonesia Petroleum Ltd.;
(b) Total Indonesie and Indonesia Petroleum Ltd.;
(c) Unocal Indonesia Company; and
(d) Virginia Indonesia Company, OPICOIL Houston, Inc., Lasmo Sanga Sanga
Limited, Union Texas East Kalimantan Limited, Universe Gas & Oil
Company, Inc. and Virginia International Company;
and such other entities that may, from time to time, execute a Supply Agreement
with Seller as well as any successors and assignees of any of the aforesaid
suppliers who shall have agreed in writing to be bound by all of the
obligations of their respective assignors under the applicable agreement with
Seller under which such suppliers make available for sale hereunder their
respective interests in the quantities of LNG to be sold hereunder.
Standard Cubic Foot (scf)
The quantity of Natural Gas, free of water vapor occupying a volume of one
Actual Cubic Foot at a temperature of 60.0 degrees Fahrenheit and at an
absolute pressure of 14.696 pounds per square inch.
Statement of Cooling Time
As defined in Subarticle 4.10.
Supply Agreement
As defined in Subarticle 3.1.
Take-or-Pay Quantity
As defined in Subarticle 7.5(a)(i).
Unloading Port
The port in Pyeong Taek near Asan Bay, Korea where Buyer's Facilities are
located or such other port in Korea as is agreed to between Buyer and Seller.
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<PAGE> 14
USCPI
The United States Consumer Price Index (determined by reference to : All Urban
Consumers (CPI-U); Unadjusted US City Average; All Items; with a base period of
1982-84=100) as published by the US Department of Labor, Bureau of Labor
Statistics.
Used Laytime
As defined in Subarticle 4.12(a).
Waiver Agreement
The agreement entered into between Seller, Seller's Suppliers, Buyer's
Transporter and Buyer which covers incidents arising out of the use of the
Loading Port and Loading Port Facilities by an LNG Tanker and modifies the
conditions of use for such port and facilities.
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<PAGE> 15
ARTICLE 2 - SALE AND PURCHASE
Seller agrees to sell and deliver at the Delivery Point and Buyer agrees to
purchase, receive and pay for, or to pay for if not taken, LNG in the
quantities and at the price in accordance with the terms and conditions of this
Contract.
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<PAGE> 16
ARTICLE 3 - SOURCES OF SUPPLY
3.1 Sources of Supply
The Natural Gas to be processed into LNG and sold and delivered
hereunder is to be produced from the Gas Supply Area. Seller
represents that it will maintain throughout the term of the Contract
the right to sell all quantities of LNG required to be sold and
delivered hereunder. In this connection, Seller represents that it has
executed or will execute from time to time as required in order to
maintain the right to sell quantities of LNG to be sold and delivered
hereunder, agreements with Seller's Suppliers under which agreements
the respective Seller's Suppliers shall make available for sale and
delivery hereunder their respective interests in the quantities of LNG
to be sold and delivered hereunder ("Supply Agreement").
3.2 Reserves of Natural Gas
(a) Seller has furnished Buyer with a statement or statements,
each entitled a "Certificate" and each dated on or prior to
December 31, 1994 of DeGolyer and MacNaughton expressing that
firm's estimate of Proved Remaining Recoverable Reserves (as
defined in the Certificate) of Natural Gas in the Gas Supply
Area. Seller represents that such estimated quantity is in
excess of Seller's Gas Supply Obligation as of the effective
date of this Contract. Hereafter, and throughout the term of
this Contract, before committing additional Natural Gas from
the Gas Supply Area to sale or other utilization, Seller shall
secure from an independent petroleum engineering consultant
firm of recognized standing in the petroleum industry,
qualified by reputation and experience in estimating reserves
of oil and natural gas in subsurface reservoirs the written
statement (a "Certificate") of such firm expressing its
estimate of Proved Remaining Recoverable Reserves of Natural
Gas in the Gas Supply Area in an amount at least equal to
Seller's Gas Supply Obligation. Seller shall furnish to Buyer
a copy of each Certificate of such independent petroleum
engineering consultant firm on which Seller relies in making
any such commitment for supply of Natural Gas from the Gas
Supply Area. Seller shall also furnish all supporting
documentation provided by such independent petroleum
engineering consultant firm in connection with the issuance of
such Certificate.
(b) If, during the term of this Contract, Seller obtains
information from its activities (including the activities of
Seller's Suppliers) in the operating fields in the Gas Supply
Area which indicates unforeseen adverse changes in the Proved
Remaining Recoverable Reserves of Natural Gas
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<PAGE> 17
in the Gas Supply Area, Seller shall promptly inform Buyer of
such situation and inform Buyer promptly of any measures which
Seller may elect to take in order to increase the amount of
Proved Remaining Recoverable Reserves of Natural Gas in the
Gas Supply Area.
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ARTICLE 4 - LOADING AND TRANSPORTATION
4.1 Transportation by Buyer
Buyer shall provide, or cause to be provided, transportation from the
Loading Port for all quantities of LNG sold and delivered under this
Contract. The LNG shall be transported to and unloaded at the
Unloading Port.
4.2 LNG Tankers
(a) Buyer, at no expense to Seller, shall at all times provide,
maintain and operate, or cause to be provided, maintained and
operated for its performance under this Contract, LNG Tankers
compatible in all respects with the Loading Port Facilities.
Should any vessel proposed to be used by Buyer as an LNG
Tanker fail to be compatible with the Loading Port Facilities
and if Seller agrees to make necessary modifications to the
Loading Port Facilities Buyer shall reimburse Seller for all
costs relating to such modifications incurred by Seller.
However, Seller shall not be obliged to make any modifications
to the Loading Port Facilities which would adversely affect
its obligations or rights under its other LNG sales contracts
or adversely affect the operation of Seller's Facilities.
Nothing herein shall excuse or suspend Buyer's purchase,
transportation, or other obligations under this Contract.
(b) The LNG Tanker shall be designed, equipped and manned so as
safely to permit the loading of an LNG Tanker Cargo Lot in
approximately twelve (12) hours of pumping time and to accept
cargo at a rate up to approximately eleven thousand (11,000)
CBM per hour (being the full design pumping rate of Seller's
loading pumps, which rate shall be subject to revision after
mutual agreement). Buyer shall cause Buyer's Transporter to
obtain, at no cost to Seller, all port approvals, marine
permits and other authorizations necessary for the use of any
LNG Tanker in Indonesia and Korea. The provisions of this
Contract applicable to LNG Tanker shall apply whether any LNG
Tanker is owned and operated by Buyer or otherwise.
4.3 Loading Port Facilities
(a) Seller shall at all times provide, maintain and operate, or
cause to be provided, maintained and operated, facilities at
the Loading Port ("Loading Port Facilities") as follows:
(i) a berth and port facilities, including a channel and
turning basin, all (together with a holding anchorage
which Seller shall cause to be designated) capable of
receiving an LNG Tanker, where such
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<PAGE> 19
LNG Tanker may safely proceed to, lie at and depart
from, always afloat at all times of the tide;
(ii) loading facilities capable of loading LNG at an
approximate rate of ten thousand (10,000) CBM per
hour at a normal operating pressure of about
forty-two and one-half pounds per square inch gauge
(42.5 psig) (3kg/CM2) at the Delivery Point. Pressure
at the Delivery Point shall never exceed one hundred
and twenty pounds per square inch gauge (120 psig)
(8.5kg/C2);
(iii) a boil-off gas return system capable of receiving
boil-off gas from an LNG Tanker at the rate required
for the loading of LNG at the rate specified in
sub-paragraph (ii) above; and
(iv) appropriate systems for telex, facsimile and radio
communication with the LNG Tanker.
(b) Seller shall not be obligated to provide facilities for repair
of LNG Tankers.
4.4 Loading Port Obligations
(a) The LNG Tanker shall utilize the Loading Port Facilities,
subject to observance of all relevant port regulations. Any
tugs, pilots, escort or other support vessels required for the
safe berthing of an LNG Tanker shall be employed at the sole
risk and expense of the LNG Tanker. Prior to each loading,
Buyer shall be responsible for determining the availability of
utilities required by the LNG Tanker at the Loading Port,
which will be provided by Seller, if available, and be for
Buyer's account.
(b) Buyer shall be responsible for payment of amounts due for
supplies and services requested by the master of the LNG
Tanker.
(c) Prior to the first sale and delivery of LNG hereunder from the
Loading Port, Seller shall sign, and cause Seller's Suppliers
to sign, the Omnibus Agreement and Waiver Agreement; Buyer
shall sign, and cause Buyer's Transporter to sign, the Waiver
Agreement; and Buyer shall cause Buyer's Transporter to sign
the Omnibus Agreement.
(d) In the interests of the smooth and timely performance of
Buyer's obligation to provide transportation of LNG purchased
under this
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<PAGE> 20
Contract, Seller shall provide assistance to Buyer and Buyer's
Transporter in obtaining equipment, supplies, services upon
the same terms as the assistance provided by Seller to other
vessels using the Loading Port.
4.5 Cargo Loading
(a) The LNG to be sold and purchased hereunder shall be pumped
into an LNG Tanker at Seller's expense through manifold
strainers of sixty (60) mesh (or such other mesh as shall be
agreed from time to time by the Parties) provided by the LNG
Tanker. Unless otherwise provided in this Contract or absent
agreement of the Parties or an unavoidable circumstance, the
LNG shall be delivered and received in full LNG Tanker Cargo
Lots.
(b) There shall be no charge for any Natural Gas boiled-off from
the LNG Tanker while berthed at the Loading Port that is
returned to the Loading Port Facilities. The LNG Tanker shall
compress such boil- off gas to the extent required to maintain
the gas pressure in the LNG Tanker's cargo tanks as well as in
the boil-off gas return line within allowable operating limits
during loading. Seller shall operate the boil-off gas return
system in a manner that will permit the gas pressure in the
LNG Tanker's cargo tanks to be maintained within the allowable
operating limits of such tanks.
4.6 Notifications of Estimated Time of Arrival at Loading Port; Cooling
Requirements
(a) Buyer shall give prompt notice to Seller by telex or
facsimile of the date and hour on which each LNG Tanker
departs from the Unloading Port or drydock/repair port
and the estimated time of arrival ("ETA") at the Loading Port.
Buyer shall include in such notice to Seller a statement of:
(i) the estimated quantity of LNG that will be required
to cool the LNG Tanker's cargo tanks to permit
continuous loading of LNG and the estimated time that
will be required for such cooling, both of which will
be based upon the date the LNG Tanker is expected to
commence loading;
(ii) any operational deficiencies in the LNG Tanker that
may affect its port performance; and
(iii) requirements for available utilities.
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<PAGE> 21
Buyer shall arrange for the LNG Tanker's master to notify
Seller regarding any change in the ETA equal to or greater
than twelve (12) hours. If the LNG Tanker's cargo tanks
require cooling or if the cooling or utilities requirements or
the condition of the LNG Tanker should change due to
circumstances discovered after transmittal of the notice
required by this paragraph (a), the master of the LNG Tanker
shall give prompt notice thereof to Seller, setting forth the
information required by this paragraph (a) and amending the
information previously given to Seller.
(b) Ninety-six (96) hours prior to the LNG Tanker's arrival at the
Loading Port, the LNG Tanker's master shall give notice by
telex or facsimile to Seller, stating its ETA. If this ETA
changes by more than six (6) hours, the LNG Tanker's master
shall promptly give notice of the corrected ETA to Seller.
(c) Forty-eight (48) hours prior to the LNG Tanker's arrival at
the Loading Port, its master shall give notice by telex or
facsimile to Seller confirming or amending its latest ETA
notice. If this ETA changes by more than six (6) hours the
master shall promptly give notice of the corrected ETA to
Seller.
(d) Twenty-four (24) hours prior to the LNG Tanker's arrival at
the Loading Port, an ETA notice shall be sent by telex or
facsimile and by radio to Seller confirming or amending the
latest ETA notice. If this ETA changes by more than two (2)
hours the master shall give prompt notice of the corrected ETA
to Seller.
(e) The master shall send a final ETA notice by telex or facsimile
and radio five (5) hours prior to the LNG Tanker's arrival at
the Loading Port.
4.7 Berthing Assignments
Seller shall determine the berthing sequence of LNG vessels at the
Loading Port in order to best ensure compliance with the overall
loading schedule of the Loading Port Facilities, as applicable
(including the Annual Program and Ninety-Day Schedule hereunder) and
shall notify the master of the LNG Tanker of its berthing priority,
upon receipt of the Notice of Readiness.
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4.8 Vessels Not Ready for Loading
(a) If an LNG Tanker arrives not ready to load for any reason,
Seller may or may not allow it to berth. In the case of an LNG
Tanker only requiring cooldown to be ready to load Seller
shall not defer berthing if such cooldown was provided for in
the most recent Ninety-Day Schedule, or if the cooldown time
is not expected to exceed six (6) hours. Whenever Buyer
notifies Seller that an LNG Tanker will require cooldown,
Seller shall make provision therefor in the Ninety-Day
Schedule as soon as Seller can do so without disrupting the
overall loading schedule or operations of the Loading Port
Facilities.
(b) If any LNG Tanker, previously believed to be ready for loading
or cooling, is determined to be not ready after being berthed,
Seller may direct the master to vacate the berth and proceed
to anchorage, whether or not other vessels are awaiting a
berth, unless it appears reasonably certain that such LNG
Tanker can be readied within four (4) hours and Seller has not
concluded that such LNG Tanker is unsafe.
(c) When an LNG Tanker at anchorage is ready for loading or
cooling its master will notify Seller. Seller shall assign a
berth to such LNG Tanker as soon as Seller is able to do so
without disrupting Seller's loading requirements or
operations.
4.9 Notice of Readiness
As soon as an LNG Tanker is securely moored at the berth or securely
anchored awaiting a berth, has received all necessary port clearances
and is able to receive LNG for loading or cooling, its master shall
give notice of readiness to Seller ("Notice of Readiness"); provided,
however, that in the event an LNG Tanker arrives at the Loading Port
prior to the date established in the Ninety-Day Schedule (and any
revisions thereof except those made after the LNG Tanker has commenced
its voyage to the Loading Port unless made as a result of delays
caused by the operations of the LNG Tanker) the Notice of Readiness
shall be deemed effective at the earlier of: (a) 0:00 a.m. local time
on the scheduled loading date; or (b) the time loading commences.
4.10 Tank Temperature for Loading and Statement of Cooling Time
Buyer shall cause Buyer's Transporter after each discharge of a cargo
at the Unloading Port to retain on board each LNG Tanker sufficient
LNG, based on normal operations of the vessel (subject to making
adequate provision for any mechanical problems of which Buyer's
Transporter is aware), to maintain, for a period of not less than
twenty-four (24) hours after the later of: (a) the actual
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arrival; or (b) 0:00 a.m. local time on the scheduled loading date of
such vessel at the Loading Port, a temperature in its cargo tanks
sufficiently cold to permit continuous loading of LNG ("Arrival
Temperature Requirement"); provided, however, that the Arrival
Temperature Requirement shall not apply upon the vessel's initial
entry into service, or in cases where the LNG Tanker proceeds directly
from a drydock/repair port to the Loading Port. When an LNG Tanker
requires cooling, the master or Buyer shall inform Seller at the time
of the first notice under Subarticle 4.6(a) and also at the time of
the Notice of Readiness pursuant to Subarticle 4.9. After the vessel
has been cooled to a temperature required to enable continuous loading
to take place, Buyer and Seller shall sign a statement of cooling time
("Statement of Cooling Time").
4.11 Quantities for Purging and Cooling of Tanks
Quantities of LNG required to purge and cool each LNG Tanker to the
temperature that will permit continuous loading of LNG shall be
delivered by Seller without charge to Buyer upon the initial entry of
such vessel into service as an LNG Tanker subsequent to gas trials and
upon its return to service after each scheduled maintenance period.
For a vessel temporarily in service as an LNG Tanker to receive such
quantities of LNG without charge to Buyer, such vessel must remain in
service for a period of not less than four (4) continuous months. All
other LNG required by the vessel for purging and cooling shall be
sold, delivered and invoiced by Seller and paid for by Buyer at the
Contract Sales Price applicable to such cargo; provided that where any
LNG Tanker, having met the Arrival Temperature Requirement, needs
purging or cooldown due to an event which does not extend the Allowed
Laytime under Subarticle 4.12, then such LNG shall be provided by
Seller without charge. The Contract Sales Price shall be applied to
the total liquid quantities delivered for purging and cooling,
measured before evaporation. The Parties will determine by mutual
agreement the rates and pressures for delivery of LNG for purging and
cooling and the method for determining quantities used for such
operations. Quantities of LNG used to bring the LNG Tanker to a
temperature permitting continuous loading of LNG shall not be applied
against the quantities required to be sold by Seller and taken, or
paid for if not taken, by Buyer under Subarticle 7.3 of this Contract.
4.12 Demurrage at Loading Port
(a) In the event used laytime in loading an LNG Tanker, as
calculated under paragraph (c) below ("Used Laytime"), exceeds
allowed laytime, as set forth in paragraph (b) below ("Allowed
Laytime"), Seller shall pay to Buyer, or for Buyer's account
if so directed by Buyer, demurrage
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("Demurrage") at a rate per day in US Dollars (reduced
pro-rata for each partial day) determined in accordance with
the following:
Demurrage rate = 126,912 x P
B
Where
n
P = P (1+i) - R
B T T
in which
P = 0.599
T
i = a fixed escalation rate of 0.025
n = 11 on January 1, 1994 and one higher
whole number on each subsequent
January 1
R = 0.029
T
Provided, however, that no Demurrage shall be payable under
this paragraph (a) for any quarter in which the aggregate
number of hours by which Used Laytime exceeds Allowed Laytime
for all voyages during such quarter is less than twenty-four
(24) hours. Buyer shall invoice Seller for Demurrage amounts
due under this paragraph (a) at the end of each calendar
quarter and Seller shall pay the invoice in accordance with
Article 10.
(b) Allowed Laytime at the Loading Port shall be twenty-four (24)
consecutive hours extended by any period of delay which is
caused by:
(i) reasons attributable to the LNG Tanker, or its
master, crew, owner or operator, including the period
of time when the LNG Tanker: (A) awaits berth by
reason of the exercise by Seller of its rights under
Subarticle 4.8; or (B) receives LNG for purging and
cooldown;
(ii) Force Majeure, as defined in Article 15;
(iii) "adverse weather conditions", which for purposes
hereof means weather and/or sea conditions actually
experienced at the Loading
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Port that are sufficiently severe either: (A) to
prevent all LNG Tankers from proceeding to berth,
loading, or departing from berth in accordance with
the weather standards prescribed in published
regulations in effect at the Loading Port; or (B) to
cause an actual determination by the master that it
is unsafe for the LNG Tanker to berth, load or depart
from berth. The period of delay to an LNG Tanker
caused by adverse weather conditions shall not be
considered to extend past the time during which such
adverse weather conditions actually prevailed, except
where additional delay is caused by the intervening
occupation of the berth by another LNG Tanker at the
Loading Port; and
(iv) any period of delay caused by occupancy of the berth:
(A) by a previous LNG Tanker, provided such occupancy
is for reasons attributable to such LNG Tanker; (B)
by either a previous LNG Tanker or another vessel on
its scheduled loading date; or (C) by either a
previous LNG Tanker, or another vessel that arrived
prior to the LNG Tanker, when the LNG Tanker arrived
after its scheduled loading date.
(c) Used Laytime shall begin to count upon the LNG Tanker being
"all fast" in berth and shall continue to run until stand-by
engine prior to departure. To Used Laytime calculated as above
shall be added:
(i) the number of hours by which the total of periods of
delay, as defined below, occurring between Notice of
Readiness and "all fast" in berth exceeds six (6);
and
(ii) the total of periods of delay occurring between
stand-by engine and the LNG Tanker clearing the
Loading Port (i.e., passing the agreed position for
tendering Notice of Readiness).
For the purposes of this paragraph (c), "delay" means all berth delays
and stoppages that prevent the forward or outward movement of the LNG
Tanker to or from the berth, the port and the approaches thereto,
including any delay caused to an LNG Tanker by quarantine at the
Loading Port.
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4.13 Effect of Loading Port Delays; Transportation Costs
(a) If an LNG Tanker is delayed in berthing and/or commencement of
loading for reasons other than Force Majeure affecting the
Loading Port Facilities or such LNG Tanker and other than the
fault of the LNG Tanker, or its master, crew, owner or
operator and if as a result thereof the commencement of
loading is delayed beyond thirty (30) hours after Notice of
Readiness has been given, then Seller shall pay Buyer an
amount, on account of excess boil-off, equal to the Contract
Sales Price multiplied by the BTU equivalent of the quantity
of LNG which is the difference between the actual quantity on
board the LNG Tanker thirty (30) hours after the giving of the
Notice of Readiness and the actual quantity on board
immediately prior to commencement of loading. If it should
appear that the commencement of loading will be delayed beyond
thirty (30) hours after Notice of Readiness has been given,
Buyer's Transporter shall notify Seller at least three (3)
hours prior to the time that it intends to measure the volume
of LNG in the LNG Tanker's tanks and Seller shall have the
right to have its representative present to witness the
measurement. Provided, however, that if Seller should not
elect to send a representative on a timely basis, Buyer's
Transporter shall proceed to make the measurement and shall
notify Buyer and Seller of the results of the measurement
promptly upon completion of measuring.
(b) If there should become due from Buyer to Buyer's Transporter
at any time any payment or payments on account of Buyer's
failure to furnish for carriage by Buyer's Transporter
sufficient quantities of LNG to fulfill Buyer's obligations
under the terms of Buyer's transportation arrangement and if
the deficiency is caused by the failure of Seller to fulfill
its obligations under this Contract, (for reasons other than
Force Majeure) then such amount shall be paid by Seller to
Buyer; provided, however, that Seller's payment obligations
under this paragraph (b) shall be subject to the following
conditions and/or limitations:
(i) Seller's compensation obligations under this
paragraph (b) shall be reduced by such amounts as
reflect a credit for all revenues earned by the LNG
Tanker during the period of its non- utilization
under this Contract; and
(ii) the basis for calculating all such payments by Buyer
to Buyer's Transporter shall be reasonable when
compared with the obligations of Seller under
Seller's transportation arrangements in similar
circumstances.
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(c) Buyer shall invoice Seller for amounts due under this
Subarticle 4.13 and Seller shall pay the invoice in accordance
with the terms of Subarticle 10.3(b).
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ARTICLE 5 - ON-SHORE FACILITIES
5.1 Buyer's Facilities
Buyer has heretofore constructed or will construct further LNG
receiving terminal facilities at the Unloading Port including without
limitation berthing and unloading facilities, LNG storage tanks,
vessel services facilities, regasification plants, and any other
facilities directly related to the use or handling of LNG which if not
operational would reduce the amount of LNG which Buyer is required to
receive hereunder ("Buyer's Facilities").
5.2 Seller's Facilities
Natural Gas reservoirs, Natural Gas production and treatment
facilities in and transportation facilities from the Gas Supply Area
including without limitation those facilities located at Bontang Bay,
East Kalimantan for treatment, compression, liquefaction, processing,
transmission, storage, berthing and loading, utilities together with
such expansion or modification of the foregoing as may be necessary,
in the opinion of Seller, to fulfill its obligations hereunder
("Seller's Facilities").
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ARTICLE 6 - DURATION OF CONTRACT
This Contract shall be effective on the date of execution hereof and continue
in effect until the expiration of the Parties' respective obligations to buy
and sell LNG, as provided in Article 7, or the earlier termination of this
Contract pursuant to either Subarticle 10.5 or Article 18. If Seller and Buyer
so agree at least five (5) years before the time this Contract would otherwise
expire, the term of this Contract may be extended on such terms and conditions
as may be mutually agreed.
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ARTICLE 7 - QUANTITIES
7.1 Fixed Quantity
During each year (each such period being called a "Fixed Quantity
Period"), Seller shall sell and deliver to Buyer and Buyer shall
purchase, receive and pay for, or pay for if not taken, at the
Contract Sales Price, the quantity of LNG specified for such Fixed
Quantity Period (each such quantity being called a "Fixed Quantity")
as follows:
Year Fixed Quantity
(Billion of BTU's) per year
----------------------------------------------------------
1998 - 2017 53,100
inclusive
The above Fixed Quantities are subject to adjustment as provided in
Subarticles 7.3 and 7.6. After giving effect to any such
adjustment(s), the term "Fixed Quantity" shall mean the applicable
Fixed Quantity as so adjusted. The respective obligations of Seller to
sell and deliver and of Buyer to purchase, receive and pay for, or to
pay for if not taken, a Fixed Quantity of LNG in any Fixed Quantity
Period shall apply to the applicable Fixed Quantity and Fixed Quantity
Period, as so adjusted.
7.2 Deliveries
Within each Fixed Quantity Period the quantities of LNG to be
delivered by Seller and received by Buyer shall be delivered and
received at rates and intervals which are reasonably constant over the
course of such Fixed Quantity Period after taking into consideration
all commitments of Seller's Facilities and the maintenance, downtime,
shipping and other matters referred to in Article 12, so as to ensure,
as nearly as practicable, an even production rate at Seller's
Facilities.
7.3 Buyer's Obligation to Take-or-Pay
(a) If, during any Fixed Quantity Period, Buyer should fail to
take the full amount of the Fixed Quantity, as may be adjusted
pursuant to this Article 7, Buyer shall pay Seller at the
Contract Sales Price in effect as of the last day of such
Fixed Quantity Period for the quantities of LNG required to be
purchased but which were not taken by Buyer during such Fixed
Quantity Period (any such quantity deficiency being called a
"Quantity Deficiency"), subject to the following provisions of
this Subarticle 7.3:
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(i) if, after taking into account all adjustments
provided in this Subarticle 7.3, including any
allowance under Subarticle 7.3(d) that has been
exercised, Buyer's Quantity Deficiency at the end of
any year amounts to less than one full LNG Tanker
Cargo Lot, it will be deemed that no Quantity
Deficiency exists for such year and the amount of
such Deficiency shall be carried forward and added to
Buyer's Fixed Quantity for the next Fixed Quantity
Period;
(ii) if, at the time an Annual Program is developed under
Subarticle 12.1, it is estimated that Buyer will have
a Quantity Deficiency in the year which is the
subject of such Annual Program in an amount that is
less than a full LNG Tanker Cargo Lot, Buyer shall
have the right to request an increase in the quantity
which Buyer wishes to take during such subject year
in an amount sufficient to fill up such cargo (such
right being hereinafter referred to as Buyer's
"Round-Up Request"). If Buyer does not make a
Round-Up Request or if Seller does not accept such
Round-Up Request, the non-delivery of the partial
cargo of LNG shall not constitute a failure of Seller
to make LNG available for sale for the purpose of
Subarticle 7.3(b). No such Round-Up Request shall,
however, operate to increase Buyer's Fixed Quantity
under this Contract. However, Buyer shall have a
take-or-pay obligation in respect of LNG quantities
that have been the subject of a Round-Up Request
which is accepted by Seller; and
(iii) if at the end of any Fixed Quantity Period Buyer has
purchased and received quantities of LNG pursuant to
this Article 7 in excess of the Fixed Quantity for
such year, other than Make-Up LNG, Make-Good LNG or
Restoration Quantities, the excess shall be applied
to reduce Buyer's Fixed Quantity during the next
Fixed Quantity Period.
(b) Buyer's obligation to pay for the Fixed Quantity not taken in
any Fixed Quantity Period pursuant to Subarticle 7.3(a) shall
be reduced by the quantity of LNG which Buyer was unable to
purchase because of Seller's failure to make such quantity
available for sale in accordance with the terms of this
Contract.
(c) In calculating the quantity of LNG delivered by Seller and
purchased by Buyer for each Fixed Quantity Period, Seller or
Buyer shall include the
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quantity delivered and purchased within the first seven (7)
days of the next year, provided such quantity was scheduled in
the Annual Program of the Fixed Quantity Period with respect
to which the calculation is being made.
(d) In calculating its take-or-pay obligations under this
Subarticle 7.3, Buyer shall be entitled to allowances
("Allowances", or individually an "Allowance") as follows:
(i) with respect to each Fixed Quantity Period, Buyer
shall be entitled to exercise an Allowance of up to
two thousand nine hundred and fifty (2,950) billion
BTU's. Provided, however, that no Allowance can be
exercised if its exercise would result in Buyer's
aggregate outstanding Allowances exceeding five
thousand nine hundred (5,900) billion BTU's.
For the purposes of this Subarticle 7.3(d)(i), and
subject to the provisions of Subarticle 7.3(d)(vii),
an Allowance, or portion thereof, shall be deemed
outstanding until either Make- Good LNG is taken
pursuant to Subarticle 7.3(d)(iv), or payment is
made, pursuant to Subarticle 7.3(d)(vi). Buyer shall
not be obligated to Make-Good a portion of an
Allowance which exceeds five (5) percent of Buyer's
total Fixed Quantity for the relevant Fixed Quantity
Period, solely by reason of either: (A) a decrease in
the total Fixed Quantity from one Fixed Quantity
Period to the next; or (B) an Allowance being deemed
outstanding following Seller's offer to supply
requested quantities of LNG pursuant to Subarticle
7.3(d)(vii)(B).
(ii) Buyer may only exercise an Allowance by delivering
written notice to Seller, as described in Subarticle
7.3(d)(iii). A notice of exercise of an Allowance,
once given, may not be later withdrawn. Provided,
however, that corrections of clerical or arithmetic
errors may be made at any time.
(iii) each notice of exercise of an Allowance shall specify
the quantity of LNG subject to the Allowance. Such
notice shall be delivered to Seller no later than
fifteen (15) days after the end of the applicable
Fixed Quantity Period to which the Allowance
specified in any such notice relates.
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(iv) each Allowance shall be made good in full (even if it
amounts to a fractional portion of a full LNG Tanker
cargo) by the purchase of an equal quantity of LNG
("Make-Good LNG") during the Allowance Restoration
Period (defined below) for such Allowance. (Such
purchase herein is referred to as "Make-Good" or
"Made-Good".) An "Allowance Restoration Period" shall
commence on January 1 of the year following the Fixed
Quantity Period for which an Allowance was exercised
and shall end on the earlier of either: (A) five (5)
calendar years thereafter or (B) June 30, 2018.
During any Fixed Quantity Period within an Allowance
Restoration Period Make-Good LNG may be taken only
after the Fixed Quantity for such Fixed Quantity
Period has been taken. If Buyer has more than one
Allowance outstanding, it shall Make-Good in the same
chronological order in which such Allowances were
exercised.
(v) for every request for Make-Good LNG, Buyer shall
specify the Allowance to which such request relates.
(vi) if, as of the end of the last day of the relevant
Allowance Restoration Period, an Allowance has not
been Made-Good in full pursuant to Subarticle
7.3(d)(iv), Buyer shall pay Seller at the Contract
Sales Price in effect on such day for the quantity of
LNG for which such Allowance has not been Made-Good.
Buyer shall have a right to Make-Up LNG, pursuant to
Subarticle 7.5, in respect of such payment.
(vii) in the event that Buyer requests quantities of LNG
for Make-Good purposes, pursuant to Subarticle
7.3(d)(v), which Seller is unable to make available
for any reason including Force Majeure, the following
applicable provisions shall apply:
(A) Buyer shall be relieved from the obligation,
under Subarticle 7.3(d)(vi), to pay for such
requested quantity as of the end of the last
day of the Allowance Restoration Period
relating thereto, except as provided in
Subarticle 7.3(d)(vii)(B).
(B) such requested quantities shall not be deemed
outstanding for the purposes of Subarticle
7.3(d)(vi), until Seller shall have offered
the same to Buyer (whether during, or after
the relevant Allowance Restoration Period)
and Buyer has
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not accepted such offer, in which event such
requested quantity shall then be deemed
outstanding for the purposes of Subarticle
7.3(d)(vi).
(C) such requested quantities may be scheduled
for delivery at any time prior to the
expiration of the last Fixed Quantity Period,
as mutually agreed by Seller and Buyer.
Provided, however, that such requested
quantities shall be delivered and taken by
June 30, 2018 and paid for in accordance with
Subarticle 10.3(b). If such requested
quantities cannot be delivered by June 30,
2018, then Buyer shall have no further
obligation to Make-Good any Allowance
exercised with respect to such requested
quantities, or to pay for such requested
quantities.
(viii) Seller shall not be obligated to reserve any LNG
production or shipping capacity for the purposes of
permitting Buyer to satisfy Make-Good obligations.
(e) A reduction shall be made to any Quantity Deficiency equal to
the amount by which such Quantity Deficiency resulted from a
partial loading of an LNG Tanker during the relevant Fixed
Quantity Period due to reasons attributable to Seller.
7.4 Force Majeure - Allocation of Deliveries Between Buyer and Other
Purchasers
(a) Whenever deliveries of LNG by Seller are reduced
below the applicable Fixed Quantities to be delivered
hereunder by reason of an event or circumstance of Force
Majeure affecting Seller's Facilities, an allocation of LNG
then capable of being delivered from Seller's Facilities will
be made between Buyer and other purchasers of LNG from
Seller's Facilities. At such times, the total quantities
capable of being delivered from Seller's Facilities shall be
allocated among the purchasers from Seller's Facilities
(including Buyer) pro-rata in the ratio of their respective
quantities which are eligible for allocation, as provided
below. The quantities eligible for such allocation shall be,
as to Buyer, the portion of the Fixed Quantities to be
purchased hereunder during the period of such Force Majeure
and, as to other purchasers, be those fixed or contract
quantities of LNG which are committed for sale from Seller's
Facilities during the period of such Force Majeure in
satisfaction of Seller's contracts with other purchasers which
provide for sales of LNG from Seller's Facilities over a term
of at least fifteen (15) years.
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(b) If such an event of Force Majeure does not preclude full
production and loading of all Fixed Quantities under the
allocation formula described in Subarticle 7.4(a), but is of
such an extent as to prevent Seller from producing and loading
all Make-Good LNG, Make-Up LNG and Restoration Quantities
scheduled for delivery from Seller's Facilities to Buyer and
LNG for the same purposes scheduled for delivery from Seller's
Facilities to other purchasers under sales contracts providing
for deliveries over a term of at least fifteen (15) years,
quantities of such LNG as are available shall be allocated
between Buyer and such other purchasers in proportion to the
respective quantities so scheduled.
7.5 Make-Up LNG
(a) (i) if, pursuant to Subarticles 7.3(a) or 7.3(d)(vi),
Buyer shall have paid for any Quantity Deficiency not
taken ("Take-or-Pay Quantity"), then during any
subsequent year Buyer may purchase up to an equal
quantity of LNG from Seller as make-up LNG ("Make-Up
LNG") to the extent not previously made up. Buyer
must request Make-Up LNG by notice to Seller in
accordance with Subarticle 12.1.
(ii) upon Buyer's request for Make-Up LNG, Seller shall
sell such quantity provided:
(A) Seller has uncommitted LNG available for such
purpose; and
(B) Buyer has first taken and paid for its Fixed
Quantity for the year in which deliveries of
Make-Up LNG are requested.
(iii) Buyer's right to take delivery of Make-Up LNG under
this Subarticle 7.5 shall expire on December 31,
2017.
(iv) if Buyer shall have requested Make-Up LNG during the
twelve (12) months prior to December 31, 2017 and
Seller shall have had insufficient uncommitted LNG to
fulfill such request, then in such circumstances, the
Parties shall consult and agree upon a deferred
schedule for Buyer to take delivery of any
outstanding balance of Take-or-Pay Quantity.
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<PAGE> 36
(b) Buyer shall pay for Make-Up LNG at the Contract Sales Price in
effect as of the date of delivery, reduced by the amount
previously paid on account of the Take-or-Pay Quantity or the
part thereof being made up by such sale.
(c) Take-or-Pay Quantities shall be made up and prior payments
applicable thereto applied in the same chronological order in
which such quantities were incurred.
7.6 Force Majeure Deficiency
(a) (i) if during any Fixed Quantity Period all or any
portion of the Fixed Quantity required to be
delivered to and taken by Buyer during such Fixed
Quantity Period is not delivered to and taken by
Buyer by reason of Force Majeure (any such quantity
not delivered and taken being a "Force Majeure
Deficiency"), Buyer may, thereafter, request that
all, or a part of such Force Majeure Deficiency be
delivered as restoration quantities ("Restoration
Quantities") during a subsequent Fixed Quantity
Period. The Restoration Quantities so agreed will be
scheduled for delivery pursuant to Article 12 at the
mutual convenience of the Parties and shall be paid
for by Buyer at the Contract Sales Price in effect as
of the date of delivery.
(ii) Seller and Buyer shall each make best efforts to
restore the Force Majeure Deficiency in full by
Seller selling and Buyer purchasing such quantities
of LNG prior to the expiration of the last Fixed
Quantity Period. In the event that, despite such best
efforts, Seller fails to deliver or Buyer fails to
take delivery of the outstanding Restoration
Quantities by the end of 2017, then any obligation of
Seller to deliver and Buyer to take delivery of such
Restoration Quantities shall cease on such date.
(b) If an event of Force Majeure relieves or delays Buyer's
performance of its obligations under this Contract and causes
a reduction in deliveries of LNG to Buyer and if Seller sells
to third parties quantities of LNG which Buyer is unable to
purchase, then the Force Majeure Deficiency shall be reduced,
up to the quantities so sold, by the amount, if any, that the
Seller's Gas Supply Obligation (including amounts so sold to
third parties) exceeds the estimate of Proved Remaining
Recoverable Reserves stated in the most recent Certificate as
a result of such sales.
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7.7 Allocation for Make-Up LNG, Make-Good LNG and Restoration Quantities
Whenever Buyer requests either: Make-Good LNG under Subarticle
7.3(d)(iv), Make-Up LNG under Subarticle 7.5 and/or Restoration
Quantities under Subarticle 7.6, and quantities of LNG are requested
for the same purposes by other purchasers from Seller's Facilities
(under LNG sales contracts with Seller with terms of at least fifteen
(15) years) and there is insufficient uncommitted LNG at Seller's
Facilities to meet all such requests, then the LNG which is available
for such purposes shall be allocated, as between Buyer on the one hand
and such other requesting purchasers on the other hand, in the same
proportion that each such purchaser's portion of its Fixed Quantity to
be purchased from Seller's Facilities for the year of requested
delivery bears to the total of all requesting purchasers' (including
Buyer) Fixed Quantities to be purchased from Seller's Facilities for
that year.
7.8 Priority Order
Make-Good LNG under Subarticle 7.3(d)(iv), Make-Up LNG under
Subarticle 7.5 and Restoration Quantities under Subarticle 7.6 shall
be delivered and taken in the following order:
(i) Make-Up LNG;
(ii) Make-Good LNG; and
(iii) Restoration Quantities.
provided, however, that Buyer shall have the option to change the
order of (i) and (ii) above, upon notice to Seller.
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ARTICLE 8 - CONTRACT SALES PRICE
8.1 Contract Sales Price
The contract sales price applicable to the quantities of LNG to be
sold and delivered at the Delivery Point and to any quantities of LNG
required to be taken but which are not taken and are required to be
paid for by Buyer under this Contract, expressed in US Dollars per
million British Thermal Units (US$/MMBTU), ("Contract Sales Price")
and shall be determined in accordance with the following provisions of
this Article 8.
The Contract Sales Price is subject to adjustment from time to time
according to the following provisions of this Article 8 and as
adjusted and in effect at any time shall be the Contract Sales Price.
The Contract Sales Price to be applied to the BTU's comprising each
LNG Tanker Cargo Lot shall be that Contract Sales Price in effect as
of the date of completion of loading of each LNG Tanker Cargo Lot.
8.2 Contract Sales Price and Adjustments Thereto
(a) The Contract Sales Price ("CSP"), as adjusted from time to
time, shall be calculated according to the following formula:
9 A 1 USCPIn
CSP = (0.9875) [-- (Po X --------)+ -- (Po_X ------) + C]
10 US$18.00 10 USCPlo
where:
CSP = the Contract Sales Price (expressed
in US$/MMBTU);
Po = US$ 3.06/MMBTU;
A = the arithmetic average of the
realized export prices per barrel in
US Dollars, f.o.b. Indonesia, of all
field classifications of Indonesian
crude oils then being sold and
exported by PERTAMINA, except
premiums and except such prices for
spot sales;
Po' = US$ 3.24/MMBTU;
USCPIn = in respect of the applicable year,
the average of the monthly values of
USCPI for the twelve-month period
commencing with the month of
November, fourteen (14) months prior
to the
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beginning of the applicable year, and
ending with the month of October,
three (3) months prior to the
commencement of the applicable year;
USCPIo = 143.8, being the arithmetic average
of the monthly values of USCPI for
the twelve-month period, November
1992 through October 1993; and
C = US$ 0.012/MMBTU.
(b) An adjustment of the Contract Sales Price to reflect any
change in USCPI shall be made on and shall be effective as of
January 1 of each year, and further adjustments of the
Contract Sales Price shall be made as of each effective date
on which:
(i) the realized export prices of more than one of the
field classifications of Indonesian crude oils sold
by PERTAMINA shall have changed from the respective
prices therefor included in the last preceding
determination of "A" made pursuant to Subarticle 8.2
(a); or
(ii) two or more field classifications of such crude oils
shall have been added to or deleted from the crude
oils being sold by PERTAMINA since the date of the
last preceding determination of "A" made pursuant to
Subarticle 8.2(a).
Procedures for verifying changes in the realized export prices
of all Indonesian crude oils and for determining the effective
date of any adjustment of the Contract Sales Price shall be
agreed upon by Seller and Buyer.
(c) Seller and Buyer shall agree a procedure for handling
corrections, revisions or changes in the calculation of USCPI.
It is agreed that if at any time the US Department of Labor,
Bureau of Labor Statistics discontinues publishing a report on
USCPI values, then Seller and Buyer shall agree upon an index
method that reflects inflation in the United States of
America's consumer prices to replace the discontinued USCPI
report.
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ARTICLE 9 - TRANSFER OF TITLE
The LNG to be sold by Seller and purchased by Buyer hereunder shall be
delivered to Buyer at the Delivery Point at the Loading Port. Delivery of LNG
shall be deemed completed and title to and risk of loss of such LNG shall pass
from Seller to Buyer as the LNG passes the Delivery Point.
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ARTICLE 10 - INVOICES AND PAYMENT
10.1 Invoices and Cargo Documents
Promptly after completion of loading of each LNG Tanker, Seller or its
representative shall furnish Buyer or Buyer's representative a
certificate of volume loaded, together with such other documents
concerning the cargo as may be reasonably requested by Buyer for the
purpose of Korean customs clearance. Seller shall within forty- eight
(48) hours of completing loading complete a laboratory analysis and
calculations to determine the quality and BTU content of the LNG
loaded and shall promptly furnish to Buyer, or Buyer's representative,
a certificate with respect thereto together with details of the
calculation of the number of BTU's loaded and sold. Promptly upon
completion of such analysis and calculation, Seller or its
representative shall furnish Buyer by telex, facsimile or telegram, an
invoice, stated in US Dollars, in the amount of the Contract Sales
Price for the number of BTU's delivered and sold. At the same time
Seller shall send to Buyer a signed copy of the invoice and relevant
documents showing the basis for the calculation thereof.
10.2 Other Invoices
In the event that any moneys are due from one Party to the other
hereunder, including, without limitation, amounts payable pursuant to
Subarticle 7.3 on account of Fixed Quantities of LNG required to be
purchased but which were not taken by Buyer, then the Party to whom
such moneys are owed shall furnish an invoice therefor, together with
relevant supporting documents showing the basis for the calculation
thereof. The procedure set forth in Subarticle 10.1 for sending
invoices shall be followed.
10.3 Invoice Due Dates
(a) Each invoice for LNG delivered to Buyer pursuant to Subarticle
10.1 shall become due and payable by Buyer on the eighth (8th)
Business Day in Korea after the date on which the invoice has
been received by Buyer in Korea. For this purpose, a telex,
facsimile or telegraphic copy of an invoice shall be deemed
received by Buyer on the next Business Day in Korea following
the day in which it was sent.
(b) Except as otherwise expressly provided in this Contract, each
invoice sent pursuant to Subarticle 10.2 shall become due and
payable by the Party receiving the invoice within twenty (20)
calendar days after the date of receipt of such invoice.
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(c) (i) if any invoice to Buyer has a due date that is not a
Business Day in Korea, such invoice shall become due
and payable by Buyer on the next Business Day in
Korea.
(ii) if any invoice to Seller has a due date that is not a
Business Day in Indonesia, such invoice shall become
due and payable by Seller on the next Business Day in
Indonesia.
(d) In the event the full amount of any invoice is not paid when
due, any unpaid amount thereof shall bear interest from the
due date until paid, at an interest rate, compounded annually,
two percent (2%) greater than the rate, or rates, being
charged during the period of delinquency by Citibank, N.A.,
New York to its prime commercial customers for ninety (90) day
loans. Such interest rate shall be adjusted up or down, as the
case may be, to reflect any changes in the aforesaid prime
rate as of the dates of such changes in the prime rate. In the
event that Citibank, N.A. shall for any reason cease quoting a
prime rate as described above, then a comparable rate shall be
determined using rates then in effect and shall be used in
place of the said prime rate.
10.4 Payment
(a) Buyer shall pay, or cause to be paid, in US Dollars, all
amounts which become due and payable by Buyer pursuant to an
invoice issued hereunder, to a bank account or accounts in the
United States of America designated by Seller. Buyer shall not
be responsible for the designated bank's disbursement of
amounts remitted by Buyer to such bank, and Buyer's deposit in
immediately available funds of the full amount of each invoice
with such bank shall constitute full discharge and
satisfaction of the obligations under this Contract for which
such amounts were remitted. Each payment by Buyer of any
amount owing hereunder shall be in the full amount due,
without reduction or offset for any reason including, without
limitation, taxes, exchange charges or bank transfer charges.
(b) Transfer of funds to the bank in the United States of America
referred to in paragraph (a) above, effected from Korea before
the close of business in Korea on or before the due date of
any invoice, shall be deemed timely payment, notwithstanding
that such United States of America bank cannot credit such
transfer as immediately available funds for a period of up to
fourteen (14) hours by reason of the time difference between
Korea and the United States of America, or for one or more
days which
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are not days when banks are open for business in the United
States of America.
(c) Seller shall pay, or cause to be paid, in US Dollars the
amounts which become due and payable by Seller pursuant to a
Subarticle 10.2 invoice to an account with a bank designated
by Buyer. Seller shall not be responsible for the designated
bank's disbursement of funds by Seller to Buyer pursuant to
this paragraph (c).
10.5 Seller's Rights Upon Buyer's Failure to Make Payment
If payment of any invoice for quantities of LNG delivered hereunder or
for the Fixed Quantity of LNG not taken and for which Buyer is
obligated to pay pursuant to this Contract is not made within sixty
(60) days after the due date thereof, Seller shall be entitled, upon
giving thirty (30) days written notice to Buyer, to suspend subsequent
deliveries to Buyer until the amount of such invoice, together with
interest thereon have been paid, and Buyer shall not be entitled to
any make-up rights in respect of such suspended deliveries. If any
such invoice is not paid within one hundred and twenty (120) days
after the due date thereof, then Seller shall have the right, at
Seller's election, upon not less than eighty (80) days notice to Buyer
to terminate this Contract, and such termination shall become
effective upon the date specified in such notice from Seller. Any such
termination shall be without prejudice to any other rights and
remedies of Seller arising hereunder, or by law, or otherwise,
including the right of Seller to receive payment of all obligations
and claims which arose or accrued prior to such termination, or by
reason of such default by Buyer.
10.6 Disputed Invoices
In the event of disagreement concerning any invoice, Buyer or Seller,
as the case may be, shall make provisional payment of the total amount
thereof and shall immediately notify the other Party of the reasons
for such disagreement, except that in the case of obvious error in
computation Buyer or Seller, as the case may be, shall pay the correct
amount after disregarding such error. Invoices may be contested by
Buyer or Seller, as the case may be, or modified only if, within a
period of ninety (90) days after receipt thereof, the disputing Party
serves notice on the other Party questioning their correctness. If no
such notice is served, such invoice shall be deemed correct and
accepted by both Parties. Promptly after resolution of any dispute as
to an invoice, the amount of any overpayment or underpayment shall be
paid by Seller or Buyer, as the case may be, to the other together
with interest at the rate provided in Subarticle 10.3(d) from the date
payment was due to the date of payment.
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ARTICLE 11 - QUALITY
11.1 Gross Heating Value
The LNG when delivered by Seller to Buyer shall have, in a gaseous
state, a Gross Heating Value of not less than 1,065 BTU's per Standard
Cubic Foot and not more than 1,180 BTU's per Standard Cubic Foot.
11.2 Components
(a) The LNG delivered by Seller to Buyer shall, in a gaseous
state, contain not less than eighty-five molecular percentage
(85 mol%) of methane (CH4) and, for the components and
substances listed below, such LNG shall not contain more than
the following:
(i) Nitrogen (N2), 1.0 mol%.
(ii) Butanes (C4) and heavier, 2.00 mol%.
(iii) Pentanes (C5) and heavier, 0.10 mol%.
(iv) Hydrogen Sulfide (H2S), 0.25 grains per 100 Standard
Cubic Feet (0.25 grains/100 scf).
(v) Total sulfur content, 1.3 grains per 100 Standard
Cubic Feet (1.3 grains/100 scf).
Although the LNG which Seller delivers to Buyer is permitted
to contain the sulfur concentrations shown in sub-paragraphs
(iv) and (v) above, under normal operating conditions at
Seller's Facilities, Seller would expect such concentrations
to be materially less.
(b) Should any question regarding quality of the LNG arise, Seller
and Buyer shall consult and cooperate concerning such question
and the proper action to be taken.
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ARTICLE 12 - PROGRAMMING OF DELIVERIES
12.1 Annual Programs
Not later than ninety (90) days prior to the beginning of each year
commencing with 1998 (the first Fixed Quantity Period), Seller shall
give written notice to Buyer of the anticipated quantities of LNG
available for delivery hereunder in each calendar quarter of the
succeeding year from Seller's Facilities and specifying any scheduled
downtime of Seller's Facilities.
On or before October 15 of each year in which such notice is given,
Buyer shall advise Seller in writing of the quantities Buyer wishes to
take during each quarter of the succeeding year and, to the extent
practicable, specifying the amount of any Make-Good LNG (for previous
Allowances), Restoration Quantities (for previous Force Majeure
Deficiencies), and Make-Up LNG (for previous Quantity Deficiencies)
and advising as to any planned downtime for Buyer's Facilities;
provided, however, that as to Make-Good LNG, Restoration Quantities or
Make-Up LNG, such advice may be given up to January 15 of the year
succeeding the notice year and the Annual Program (as defined below)
shall be amended as promptly as practicable to reflect such late
advice. Seller and Buyer shall consult together with a view to
reaching agreement by December 1 of the notice year and thereafter
Seller shall issue a programming schedule, including projected dates
for quantities to be loaded in full LNG Tanker Cargo Lots at Seller's
Facilities during each month of the succeeding year ("Annual
Program"). In so doing, Seller shall take into consideration the
contents of the above notices and the Coordinated Maintenance Schedule
(as defined in Subarticle 12.3, below).
The Annual Program shall take into account Seller's commitments to
other purchasers of LNG from Seller's Facilities. The Annual Program
and the Ninety-Day Schedule referred to in Subarticle 12.2 (together
with any revision to each), are intended to assist the Parties in
planning their respective operations during the periods involved and
shall not reduce the entitlement of either Party during any Fixed
Quantity Period to sell, deliver and be paid for, or to purchase and
receive, as the case may be, the quantities of LNG required under
Article 7.
12.2 Ninety-Day Schedule
Not later than the 15th day of each month Seller shall, after
discussion with Buyer, deliver to Buyer a three (3) month forward plan
of deliveries ("Ninety-Day Schedule") which follows the applicable
Annual Program (or most current draft thereof) as nearly as
practicable. Each Ninety-Day Schedule shall reflect all adjustments,
if any, necessitated by deviation from the prior Ninety-Day
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<PAGE> 46
Schedule so as to maintain, as far as practicable, the scheduled
loadings forecast in the Annual Program. Both Parties shall cooperate
to facilitate smooth performance of the Ninety-Day Schedule. After
consultation with Buyer, Seller shall revise the Ninety-Day Schedule,
when appropriate, to meet operational requirements with the overall
objective of fulfilling the Annual Program as far as practicable,
taking into account any requests of Buyer for adjustments.
12.3 Maintenance and Inspection Coordination
Not later than ninety (90) days prior to the beginning of each year,
Seller and Buyer shall consult and agree on a program designed to
coordinate the anticipated scheduled maintenance/inspection downtime
during that year of: (a) Buyer's Facilities; (b) Seller's Facilities;
and (c) the LNG Tanker. Such program ("Coordinated Maintenance
Schedule") will be established so as to minimize the collective impact
of such downtime periods on the delivery of LNG hereunder.
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ARTICLE 13 - MEASUREMENTS AND TESTS
13.1 Parties to Supply Devices
(a) Buyer shall supply, operate and maintain, or cause to be
supplied, operated and maintained, suitable gauging devices
for the LNG tanks of the LNG Tanker, as well as pressure and
temperature measuring devices, and any other measurement or
testing devices which are incorporated in the structure of the
LNG Tanker or customarily maintained on shipboard.
(b) Seller shall supply, operate and maintain, or cause to be
supplied, operated and maintained, devices required for
collecting samples and for determining quality and composition
of the delivered LNG and any other measurement or testing
devices which are necessary to perform the measurement and
testing required hereunder at Seller's Facilities.
13.2 Selection of Devices
All devices provided for in this Article 13 not hitherto used in an
existing LNG trade shall be chosen by mutual agreement of the Parties
and shall be such as are, at the time of selection, the most accurate
and reliable in their practical application. The required degree of
accuracy of such devices selected shall be mutually agreed upon and
verified by Buyer and Seller in advance of their use, and such degree
of accuracy shall be verified by an independent surveyor who is
mutually agreed upon by Buyer and Seller. All such devices shall be
subject to approval by the appropriate Indonesian and Korean
governmental authorities.
13.3 Units of Measurement and Calibration
The Parties shall cooperate closely in the design, selection and
acquisition of devices to be used for measurements and tests under
this Article 13 in order that, to the maximum extent possible, all
measurements and tests may be conducted either in United States units
of measurement or in metric units of measurement. In the event that it
becomes necessary to make measurements and tests using a new system of
units of measurement, the Parties shall establish mutually agreeable
conversion tables. Measurement devices shall be calibrated in the
following units:
40
<PAGE> 48
<TABLE>
<S> <C> <C>
Measurement United States Units Metric Units
Volume Cubic Feet Cubic Meters
Temperature Degrees Fahrenheit Degrees Celsius
Pressure Pounds per square inch Kilograms per square centimeter
or inches of mercury or millimeters of mercury
Length Feet Meters
Weight Pound Kilograms
Density Pounds per Cubic Foot Kilograms per cubic Meter
</TABLE>
13.4 Tank Gauge Tables of LNG Tankers
Buyer shall furnish to Seller, or cause Seller to be furnished, a
certified copy of tank gauge tables as described in Section 2 of
Schedule A for each tank of each LNG Tanker.
13.5 Gauging and Measuring LNG Volumes Delivered
Volumes of LNG delivered under this Contract will be determined by
gauging the LNG in the tanks of the LNG Tanker immediately before and
after loading. Gauging the liquid in the tanks of the LNG Tanker and
measuring of liquid temperature, vapor temperature, and absolute vapor
pressure in each LNG tank and trim and list of the LNG Tanker shall be
performed, or caused to be performed, by Buyer before and after
loading. The first gauging and measurements shall be made immediately
before the commencement of loading. The second gauging and measurement
shall take place immediately after completion of loading. Copies of
gauging and measurement records shall be furnished to Seller. Gauging
devices shall be selected, and measurements shall be effected, in
accordance with the terms of Sections 3 and 4 of Schedule A.
13.6 Samples for Quality Analysis
Representative samples of the delivered LNG shall be obtained by
Seller as provided in Section 5 of Schedule A.
13.7 Quality Analysis
The samples referred to in Subarticle 13.6 shall be analyzed, or
caused to be analyzed, by Seller in accordance with the terms of
Section 5 of Schedule A in order to determine the mol fraction of the
hydrocarbons and other components in the sample.
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<PAGE> 49
13.8 Operating Procedures
All measurements, gauging and analyses provided for in Subarticles
13.5, 13.6 and 13.7, shall be witnessed and verified by an independent
surveyor who is mutually agreed upon by Buyer and Seller. Prior to
effecting such measurements, gauging and analyses the Party
responsible for such operations shall notify the surveyor, allowing
such surveyor a reasonable opportunity to be present for all
operations and computations; provided, however, that the absence of
the surveyor after notification and opportunity to attend shall not
prevent any operation or computation from being performed. The results
of such surveyor's verifications shall be made available promptly to
each Party. All records of measurements and the computation results
shall be preserved by the Party responsible for effecting such
measurements and held available to the other Party for a period of not
less than three (3) years after such measurements and computations
have been completed.
13.9 BTU Quantity Delivered
The quantity of BTU's sold and delivered shall be calculated by Seller
following the procedures set forth in Section 6 of Schedule A and
shall be verified by an independent surveyor mutually agreed upon by
Seller and Buyer.
13.10 Verification of Accuracy and Correction for Error
(a) Each Party shall test and verify the accuracy of its gauging
devices at intervals to be agreed between the Parties. In the
case of gauging devices on the LNG Tanker such tests and
verifications shall take place during scheduled drydocking
periods. Each Party shall have the right to inspect at any
time the gauging devices installed by the other Party,
provided that the other Party shall be notified in advance.
Testing shall be performed using methods recommended by the
manufacturer or any other method agreed upon by Seller and
Buyer. Tests shall be witnessed and verified by an independent
surveyor who is mutually agreed upon by Buyer and Seller.
(b) Permissible tolerances shall be as described in Section 3 of
Schedule A. Inaccuracy of a device exceeding the permissible
tolerances shall require correction of recordings, and
computations made on the basis of those recordings, to correct
all errors with respect to any period which is definitely
known or agreed upon by the Parties, as well as adjustment of
the device. In the event that the period of error is neither
known nor agreed upon, corrections shall be made for each
delivery made during the last half of the period since the
date of the most recent calibration of the inaccurate device.
However, the provisions of this Subarticle 13.10 shall
42
<PAGE> 50
not be applied to require the modification of any invoice
which has become final pursuant to Subarticle 10.6.
13.11 Costs and Expenses of Tests and Verifications
All costs and expenses for testing and verifying Seller's measurement
devices shall be borne by Seller. All costs and expenses for testing
and verifying Buyer's measurement devices shall be borne by Buyer. The
fees and charges of independent surveyors for measurements and
calculations shall be borne equally between Seller and Buyer.
43
<PAGE> 51
ARTICLE 14 - DUTIES, TAXES AND CHARGES
14.1 Indonesian Taxes
Seller shall pay (or shall reimburse Buyer for any such payments made
by it) all taxes, royalties, duties or other imposts levied or imposed
by the Indonesian Government, or any subdivision thereof, or any other
governmental authority in Indonesia, on the sale or export of LNG
under this Contract.
14.2 Port Charges
Buyer shall be responsible for payment of all normal port charges and
all shipping, freight or other taxes to the extent such charges and
taxes are uniformly applied to all vessels receiving exports of LNG
from the Loading Port.
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<PAGE> 52
ARTICLE 15 - FORCE MAJEURE
15.1 Events of Force Majeure
Neither Seller nor Buyer shall be liable for any delay or failure in
performance hereunder if and to the extent such delay or failure in
performance directly results from any of the following causes or
events not reasonably within the control of such Party ("Force
Majeure"):
(a) as to Seller's Facilities and/or Buyer's Facilities:
(i) fire, flood, atmospheric disturbance, lightning,
storm, typhoon, tornado, earthquake, landslide, soil
erosion, subsidence, washout or epidemics;
(ii) war, riot, civil war, blockade, insurrection, acts of
public enemies or civil disturbances;
(iii) strike, lockout or other industrial disturbances;
(iv) serious accidental damage to or serious failure of
Seller's Facilities;
(v) serious accidental damage to or serious failure of
Buyer's Facilities;
(vi) the Proved Remaining Recoverable Reserves of Natural
Gas in the Gas Supply Area expressed in the then most
recent Certificate which can economically be produced
have been fully depleted;
(vii) delay in completion and testing of any stage of the
expansion to Seller's Facilities contemplated by
Seller in connection with the performance of this
Contract so as to prevent the same from becoming
operational on a continuing basis, which delay is
caused by delay in receiving major items of equipment
or materials from the manufacturer or vendor thereof
provided that a Party shall have taken all steps
reasonably available to obtain timely delivery of
such items including the placing of purchase orders
within such time as was prudent under then existing
circumstances; or
45
<PAGE> 53
(viii) acts of government that directly affect the ability
of a Party to perform any obligation hereunder, other
than the obligation to remit payments as provided in
Subarticle 10.4 on account of LNG delivered and taken
or not taken but required to be paid for under this
Contract;
(b) as to the LNG Tanker:
(i) loss of the LNG Tanker or serious accidental damage
thereto requiring removal of such LNG Tanker from
service;
(ii) fire, flood, atmospheric disturbance, lightning,
typhoon, tornado or epidemics;
(iii) war, riot, civil war, blockade, insurrection, acts of
public enemies or civil disturbances;
(iv) strike, lockout or other industrial disturbance
occurring aboard the LNG Tanker or at a port or other
facility at which such LNG Tanker calls; or
(v) acts of government.
15.2 Notice, Resumption of Normal Performance
(a) Immediately upon the occurrence of an event of Force Majeure
that gives a Party warning that the event may delay or prevent
the performance by Seller or Buyer of any of its obligations
hereunder, the Party affected shall give notice thereof to the
other Party describing such event and stating the obligations
the performance of which are, or are expected to be, delayed
or prevented and (either in the original or in supplemental
notices) stating:
(i) the estimated period during which performance may be
suspended or reduced, including, to the extent known
or ascertainable, the estimated extent of such
reduction in performance; and
(ii) the particulars of the program to be implemented to
ensure full resumption of normal performance
hereunder.
(b) In order to ensure resumption of normal performance of this
Contract within the shortest practicable time, the Party
affected by an event of
46
<PAGE> 54
Force Majeure shall take all measures to this end which are
reasonable in the circumstances, taking into account the
consequences resulting from such event of Force Majeure. Prior
to resumption of normal performance, the Parties shall
continue to perform their obligations under this Contract to
the extent not prevented by such event of Force Majeure.
15.3 Settlement of Industrial Disturbances
Settlement of strikes, lockouts or other industrial disturbances shall
be entirely within the discretion of the Party experiencing such
situations, and nothing herein shall require such Party to settle
industrial disputes by yielding to demands made on it when it
considers such action inadvisable.
47
<PAGE> 55
ARTICLE 16 - ARBITRATION, REFERENCE TO EXPERT
16.1 Arbitration
If any dispute arises between Seller and Buyer in connection with this
Contract or the interpretation, performance, or non-performance
hereof, Seller and Buyer shall discuss such dispute in an attempt to
resolve such dispute amicably. If, within sixty (60) days of the
commencement of such discussion, such dispute cannot be resolved,
either Party may refer the matter to arbitration. Such arbitration
shall be conducted in accordance with the Rules of Arbitration of the
International Chamber of Commerce in effect at the time, by three
arbitrators appointed in accordance with said Rules. Arbitration shall
be in the English language and held in Paris, France, unless another
location is selected by mutual agreement of the Parties. The award
rendered by the arbitrators shall be final and binding upon the
Parties.
16.2 Disputes of a Technical Nature
Notwithstanding the terms of Subarticle 16.1, if a dispute of a
technical nature arises in connection with the interpretation,
performance or non-performance of any of the provisions of Article 13,
either Party may submit the matter for expert resolution to the
National Bureau of Standards of the United States Department of
Commerce ("NBS") within ten (10) days of a request by either Party for
the appointment of such an authority, or to such competent, impartial
authority, other than the NBS, as the Parties may agree upon.
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<PAGE> 56
ARTICLE 17 - APPLICABLE LAW
This Contract shall be governed by and interpreted in accordance with the laws
of the State of New York, United States of America. The Parties agree that the
U.N. Convention on Contracts for the International Sale of Goods and the
Convention on the Limitation Period in the International Sale of Goods shall
not apply to this Contract and the respective rights and obligations of the
Parties hereunder.
49
<PAGE> 57
ARTICLE 18 - TERMINATION
Seller and Buyer shall use best endeavors to obtain all authorizations,
approvals and permissions of national and local governments or other competent
authorities or bodies which are required for performance of this Contract
("Authorizations and Approvals"), and will cooperate fully with each other
wherever necessary for this purpose. If Seller or Buyer should fail to obtain
the Authorizations and Approvals within six (6) months after the execution of
this Contract, or should Seller fail to arrange the financing for any expansion
of Seller's Facilities ("Financing") within six (6) months after the execution
of this Contract, then such Party shall promptly notify the other Party upon
such failure, and Seller and Buyer shall consult as to the circumstances
pertaining thereto. If, within thirty (30) days after the date of the aforesaid
notice, the Parties have not agreed on a postponement of the time within which
the Authorizations and Approvals shall be obtained, or Financing arranged then
either Seller or Buyer may terminate this Contract by written notice given at
any time prior to the date upon which the Authorizations and Approvals are
obtained or Financing arranged. The same right of termination and procedures
relating thereto shall apply upon the expiration of any postponement period or
periods agreed to between the Parties. Termination of this Contract shall be
without prejudice to any accrued rights of the Parties arising under this
Contract prior to termination.
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ARTICLE 19 - CONFIDENTIALITY
No Party to this Contract shall use or communicate to third parties the
contents of this Contract or other confidential information or documents which
may come into the possession of such Party in connection with the performance
of this Contract without the prior agreement of the Party to which such
information or documents are confidential. This restriction shall not apply to
the contents of this Contract, information, or documents which:
(a) have fallen into the public domain otherwise than through the
act or failure to act of the Party that has obtained them; or
(b) are communicated to:
(i) any of Seller's Suppliers, or any Affiliate, with the
obligation of the receiving person to maintain
confidentiality;
(ii) persons participating in the implementation of this
project, such as Buyer's Transporter, legal counsel,
accountants, other professional, business or
technical consultants and advisers, underwriters or
lenders, with the obligation of the receiving persons
to maintain confidentiality; or
(iii) any governmental agency of the Republic of Indonesia
or Korea or having jurisdiction over any of Seller's
Suppliers or any Affiliate, provided that such agency
has authority to require such disclosure and that
such disclosure is made in accordance with that
authority.
51
<PAGE> 59
ARTICLE 20 - NOTICES
All notices and other communications for purposes of this Contract shall be
written in English and shall be by letter, telex, facsimile or cable, except
that notices given from ships at sea may be by radio. Notices and other
communications given by telex, facsimile or cable shall be confirmed by letter,
unless otherwise agreed by the Parties. Notices and communications shall be
directed as follows:
(a) To Seller at the following address:
PERUSAHAAN PERTAMBANGAN MINYAK DAN GAS BUMI NEGARA
(PERTAMINA)
Attention: General Manager
Gas Marketing Department
P.O. Box 1012/JKT
Medan Merdeka Timur 1A,
Jakarta 10110, Indonesia
and at the following cable, facsimile and telex addresses:
Cable: PERTAMINA JAKARTA, INDONESIA
Telex: 46471-45077-44441-46552-46554-45347
PERTAMINA JAKARTA, INDONESIA
Facsimile: 3458312
In each case marked for the attention of:
General Manager, Gas Marketing Department
(b) To Buyer at the following address:
KOREA GAS CORPORATION
Attention: Director
LNG Purchase Division
942, Daichi 3-Dong
Kangnam-Ku
Seoul, 135-283 Korea
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<PAGE> 60
and at the following cable, telex and facsimile addresses:
Cable: KOGAS SEOUL
Telex: KOGAS 28167
Facsimile: 528-2626 or 528-2627
In each case marked for the attention of :
Director, LNG Purchase Division
The Parties may designate additional addresses for particular communications
and may change any address, by notice given thirty (30) days in advance of such
addition or change. Immediately upon receiving communications by telex,
facsimile, cable, or radio, a Party shall acknowledge receipt by the same means
and may request a repeat transmittal of the entire communication, or
confirmation of particular matters. If the sender receives no acknowledgment of
receipt within 24 hours, or receives a request for repeat transmittal or
confirmation, said Party shall repeat the transmittal or answer the particular
request. Unless otherwise expressly provided in this Contract, all notices
hereunder shall become effective upon receipt. The Parties shall maintain radio
channels, frequencies and procedures for all communications between the LNG
Tanker, the Loading Port Facilities or Buyer's Facilities and the authorities
for the Loading Port or Unloading Port, as applicable.
53
<PAGE> 61
ARTICLE 21 - ASSIGNMENT
Neither this Contract nor any rights or obligations hereunder may be assigned
by Buyer without the prior written consent of Seller, or by Seller without the
prior written consent of Buyer, which consent in either of the foregoing cases
shall not be unreasonably withheld or delayed. Any such purported assignment
without the aforesaid consent shall be null and void.
54
<PAGE> 62
ARTICLE 22 - AMENDMENT AND WAIVER
22.1 Amendment
This Contract cannot be amended, modified, varied or supplemented
except by an instrument in writing signed by Seller and Buyer.
22.2 Waiver
The failure of any Party at any time to require performance of any
provision of this Contract shall not affect its right to require
subsequent performance of such provision. Waiver by any Party of any
breach of any provision hereof shall not constitute the waiver of any
subsequent breach of such provision. Performance of any condition or
obligation to be performed hereunder shall not be deemed to have been
waived or postponed except by an instrument in writing signed by the
Party who is claimed to have granted such waiver or postponement.
55
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ARTICLE 23 - DETAILS OF PERFORMANCE
Details necessary for performance of this Contract shall be mutually agreed
upon by Seller and Buyer.
56
<PAGE> 64
ARTICLE 24 - JOINT COORDINATING COMMITTEE
(a) Each of the Parties will promptly appoint representatives to a Joint
Technical and Operating Committee ("Joint Coordinating Committee"),
which shall hold its first meeting within sixty (60) days after the
execution of this Contract and thereafter at such intervals as shall
be decided upon by the Committee. The Committee, and such other
technical representatives as may be designated, shall consult together
to coordinate plans relating to the construction or modification of
vessels which Buyer intends to use as LNG Tankers ("Proposed LNG
Tankers"), so as to assure that such vessels are compatible for all
purposes and that progress is being made in accordance with the
project timetable agreed to between the Parties.
(b) No later than three (3) months after the date hereof, Buyer shall
furnish to the Joint Coordinating Committee a construction schedule
detailing the schedule of construction for each of the Proposed LNG
Tankers, the proposed schedule for obtaining port approvals, marine
permits and other authorizations therefor, and the expected date of
delivery thereof. Buyer shall inform the Joint Coordinating Committee
of any event or occurrence that in any way adversely affects the
expected date on which a Proposed LNG Tanker is to enter into service.
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ARTICLE 25 - SCOPE
This Contract constitutes the entire agreement between the Parties relating to
the subject matter hereof and supersedes and replaces any provisions on the
same subject contained in any other agreement between the Parties, whether
written or oral, prior to the date of the execution hereof.
58
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ARTICLE 26 - LANGUAGE OF THE CONTRACT
This Contract is made and executed in the English language.
59
<PAGE> 67
ARTICLE 27 - HEADINGS
The headings and captions in this Contract are inserted solely for the sake of
convenience and shall not affect the interpretation or construction of this
Contract.
60
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ARTICLE 28 - COUNTERPARTS
This Contract is executed in two identical counterparts, each of which shall
have the force and dignity of an original and both of which shall constitute
but one and the same Contract.
IN WITNESS WHEREOF, each of the Parties has caused this Contract to be executed
in Jakarta on August 12, 1995 by its duly authorized representative as of the
date first above written.
SELLER: BUYER:
PERUSAHAAN PERTAMBANGAN KOREA GAS CORPORATION
MINYAK DAN GAS BUMI
NEGARA (PERTAMINA)
By: /s/ F. ABDA'OE By: /s/ HAN, KAP-SOO
------------------------------- ----------------------------------
Name: F. Abda'oe Name: Han, Kap-Soo
Title: President Director & C.E.O. Title: President & C.E.O.
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<PAGE> 69
LNG SALES AND PURCHASE CONTRACT (BADAK V)
BETWEEN PERTAMINA AND KOREA GAS CORPORATION
The following describes Schedule A to the LNG Sales and Purchase Contract
(Badak V) between Pertamina and Korea Gas Corporation, which is omitted herein,
but will be furnished upon request:
Schedule A - Testing and Methods (Sets forth detailed procedures for sampling
and analyzing LNG for gauging and calculating the density and heating value of
LNG.
Table 1 - Physical Constants
Table 2 - Molar Volumes of Individual Components
Table 3 - Correction C for Volume Reduction of Mixture
Table 4 - Example of LNG Density Calculation
Table 5 - Example of Gross Heating Value Calculation
Table 6 - Example of Gross Heating Value Calculation
In addition Side Letter, dated August 12, 1995, to the LNG Sales and
Purchase Contract (Badak V) (regarding the HNS Convention and
Omnibus Agreement), is omitted herein but will be furnished upon
request.
<PAGE> 1
LNG SALE AND PURCHASE CONTRACT
(BADAK VI)
BETWEEN
PERUSAHAAN PERTAMBANGAN MINYAK DAN GAS BUMI NEGARA
(PERTAMINA)
AND
CHINESE PETROLEUM CORPORATION
EFFECTIVE AS OF OCTOBER 25, 1995
<PAGE> 2
TABLE OF CONTENTS
<TABLE>
<CAPTION>
Page
<S> <C> <C> <C>
ARTICLE 1 - DEFINITIONS 2
ARTICLE 2 - SALE AND PURCHASE 10
ARTICLE 3 - SOURCES OF SUPPLY 11
ARTICLE 4 - TRANSPORTATION AND UNLOADING 13
ARTICLE 5 - ON-SHORE FACILITIES 20
ARTICLE 6 - DURATION OF CONTRACT 23
ARTICLE 7 - QUANTITIES 24
ARTICLE 8 - CONTRACT SALES PRICE 33
ARTICLE 9 - TRANSFER OF TITLE 36
ARTICLE 10 - INVOICES AND PAYMENT 37
ARTICLE 11 - QUALITY 41
ARTICLE 12 - PROGRAMMING AND SHIPPING MOVEMENTS 42
ARTICLE 13 - MEASUREMENTS AND TESTS 44
ARTICLE 14 - DUTIES, TAXES AND CHARGES 52
ARTICLE 15 - FORCE MAJEURE 54
ARTICLE 16 - ARBITRATION 57
ARTICLE 17 - APPLICABLE LAW 58
ARTICLE 18 - AUTHORIZATIONS AND APPROVALS; FINANCING 59
ARTICLE 19 - CONFIDENTIALITY 60
ARTICLE 20 - NOTICES 61
ARTICLE 21 - JOINT COORDINATING COMMITTEE 63
ARTICLE 22 - MISCELLANEOUS 64
SCHEDULE A - TESTING AND METHODS
</TABLE>
<PAGE> 3
This CONTRACT is made this 25th day of October, 1995
BETWEEN
1. PERUSAHAAN PERTAMBANGAN MINYAK DAN GAS BUMI NEGARA ("PERTAMINA"), P.O.
Box 1012, Jalan Medan Merdeka Timur No.1A, Jakarta 10110, Indonesia;
and
2. CHINESE PETROLEUM CORPORATION, of 83 Chung Hwa Road, Taipei, Taiwan.
WITNESSETH:
WHEREAS:
A. The Parties entered into a Memorandum of Understanding dated December
6, 1994 with respect to the sale and purchase of quantities of LNG
during 1998 to 2017; and
B. The Parties now desire to enter into this Contract to formally provide
for the terms and conditions upon which the LNG referred to above will
be sold and purchased.
In consideration of the foregoing and the mutual promises and undertakings
herein the Parties agree as follows:
<PAGE> 4
ARTICLE 1 - DEFINITIONS
The terms or expressions set out below will have the following meanings in this
Contract. Except as otherwise specifically provided, the singular shall include
the plural or vice versa.
1.1 Actual Cubic Foot
A volume equal to the volume of a cube whose edge is one foot.
1.2 Adverse Weather Conditions
As defined in Section 4.5(b)(vi).
1.3 Affiliate
As defined in Article 19.
1.4 Allowance
The quantity of LNG by which Buyer reduces a Quantity Deficiency in
respect of a given calendar year pursuant to the provisions of Section
7.3(d).
1.5 Allowance Restoration Period
As defined in Section 7.3(d)(iv).
1.6 Allowed Laytime
As defined in Section 4.5(b).
1.7 Annual Program
As defined in Section 12.1(a).
1.8 Authorizations and Approvals
As defined in Article 18.
1.9 British Thermal Unit (BTU)
The amount of heat required to raise the temperature of one
avoirdupois pound of pure water from 59.0 Defrees F to 60.0 Degrees F
at an absolute pressure of 14.696 pounds per square inch.
1.10 Business Day
As to a given jurisdiction, every day other than Saturdays, Sundays,
and national holidays (including compensatory days) in such
jurisdiction.
<PAGE> 5
1.11 Buyer
Chinese Petroleum Corporation, a corporation organized under the laws
of Taiwan or the successor in interest to such corporation or the
permitted assignee of such corporation or such successor in interest.
1.12 Buyer's Facilities
As defined in Section 5.1.
1.13 Buyer Force Majeure
As defined in Section 4.7(a).
1.14 Cargo
That quantity of LNG (stated in MMBTUs) which represents, for purposes
of calculations hereunder, the maximum amount of LNG that can
practicably be delivered by the LNG Tanker taking into account vessel
capacity, port restrictions, and other relevant considerations.
1.15 Certificate
As defined in Section 3.2(a).
1.16 Contract
This LNG Sale and Purchase Contract, including Schedule A annexed
hereto and forming a part hereof, as it may from time to time be
amended, modified, varied or supplemented in accordance with Section
22.2.
1.17 Contract Sales Price
As defined in Section 8.1.
1.18 Coordinated Maintenance Schedule
As defined in Section 12.3.
1.19 Cubic Meter
A volume equal to the volume of a cube whose edge is one meter.
1.20 Dedicated LNG Tanker
For the Fixed Quantity periods 1998 and 1999, the Dedicated LNG Tanker
shall be the "Dwiputra", an LNG tanker under long term time charter to
Seller. For the Fixed Quantity Periods 2000 to 2017, the Dedicated LNG
Tanker shall be a new-build LNG tanker with a loaded Cargo size of at
least 135,000 cubic meters, with a discharge capacity of a full cargo
in twelve (12) hours and having a design consistent with the
requirements of Section 5.1.
<PAGE> 6
1.21 Delivery Point
The point at an Unloading Port where the flange coupling of Buyer's
unloading line joins the flange coupling of the LNG discharging
manifold on board the LNG Tanker.
1.22 ETA
Estimated time of arrival as defined pursuant to Section 4.3(a)(i).
1.23 Event
As defined in Section 4.5(c).
1.24 Excess Laytime
As defined in Section 4.5(c).
1.25 Excess Laytime Allowance
As defined in Section 4.5(c).
1.26 Financing
As defined in Article 18.
1.27 Fixed Quantity
As defined in Section 7.1.
1.28 Fixed Quantity Period
As defined in Section 7.1.
1.29 Force Majeure
As defined in Section 15.1.
1.30 Force Majeure Deficiency
As defined in Section 7.6(a).
1.31 Gas Supply Area
The areas in East Kalimantan, Indonesia, covered by production sharing
contracts between Seller and Seller's Suppliers, and such other nearby
contract areas as Seller may designate from time to time.
<PAGE> 7
1.32 Gross Heating Value
The quantity of heat expressed in British Thermal Units produced by
the complete combustion in air of one cubic foot of anhydrous gas, at
a temperature of 60.0 Degrees F and at an absolute pressure of 14.696
pounds per square inch, with the air at the same temperature and
pressure as the gas, after cooling the products of the combustion to
the initial temperature of the gas and air, and after condensation of
the water formed by combustion.
1.33 Joint Coordinating Committee
The joint technical and operating committee provided for in Article 21.
1.34 Liquefied Natural Gas (LNG)
Natural Gas in a liquid state at or below its boiling point at a
pressure of approximately one atmosphere.
1.35 LNG Element
As defined in Section 8.1.
1.36 LNG Tankers
The Dedicated LNG Tanker and Substitute LNG Tankers, and "LNG Tanker"
means either the Dedicated LNG Tanker or a Substitute LNG Tanker.
1.37 Loading Port
The port located at and forming a part of Seller's Facilities.
1.38 Make-Good LNG
As defined in Section 7.3(d)(iv).
1.39 Make-Good Obligation
The obligation of Buyer as set forth in Section 7.3(d)(iv) to take and
pay for LNG in an amount (measured in BTUs) equal to each Allowance
exercised.
1.40 Make-Up LNG
As defined in Section 7.5.
1.41 MMBTU
One million (1,000,000) BTUs.
<PAGE> 8
1.42 Natural Gas
Any hydrocarbon or mixture of hydrocarbons consisting essentially of
methane, other hydrocarbons, and non- combustible gases in a gaseous
state and which is extracted from the subsurface of the earth in its
natural state, separately or together with liquid hydrocarbons.
1.43 Ninety-Day Schedule
As defined in Section 12.2.
1.44 Non-Utilization Cost
As defined in Section 4.7.
1.45 Notice of Readiness
The notice given at the time prescribed in Section 4.5(a) by the
Master of an LNG Tanker or its agent to Buyer by letter, telegraph,
telex, facsimile, radio or telephone that such LNG Tanker is ready to
discharge LNG.
1.46 Parties
Both Seller and Buyer, and "Party" means either of Buyer or Seller.
1.47 Port Charges
All charges of whatsoever nature (including rates, tolls and dues of
every description) in respect of an LNG Tanker entering, using or
leaving a port, including charges made in respect of marking and
lighting the port and charges in respect of work performed, services
rendered or facilities provided.
1.48 Prime Rate
The rate of interest announced from time to time by Citibank, N.A.,
New York ("Citibank") as Citibank's prime rate. The prime rate may not
be the lowest rate charged by Citibank to its borrowers. If there is
any doubt as to the Prime Rate for any period, a written confirmation
signed by an officer of Citibank shall conclusively establish the
Prime Rate in effect for such period. In the event that Citibank shall
for any reason cease quoting a prime rate as described above, then a
comparable rate shall be determined using rates then in effect and
shall be used in place of the said prime rate.
1.49 Proved Remaining Recoverable Reserves
Reserves which have been proved to a high degree of certainty by
reason of actual completion, successful testing or in certain cases by
adequate core analyses, and which are defined areally by reasonable
geological interpretation of structure and known continuity of oil- or
gas-saturated material.
<PAGE> 9
1.50 Quantity Deficiency
As defined in Section 7.3(a).
1.51 Restoration Quantities
As defined in Section 7.6(a).
1.52 Round-Up Request
As defined in Section 7.3(a)(ii).
1.53 Seller
Perusahaan Pertambangan Minyak dan Gas Bumi Negara ("PERTAMINA"), a
State Enterprise of the Republic of Indonesia, or the successor in
interest of such enterprise, or the permitted assignee of such
enterprise or such successor in interest.
1.54 Seller's Facilities
As defined in Section 5.2.
1.55 Seller's Gas Supply Obligation
From time to time on any given date, the amount of Natural Gas
required to satisfy all the remaining obligations of Seller on such
date to supply LNG or Natural Gas from the Gas Supply Area both to
Buyer and other buyers plus the amount of Natural Gas from the Gas
Supply Area required to supply any additional commitment or
commitments which Seller anticipates making.
1.56 Seller's Suppliers
In respect of portions of the LNG to be sold hereunder :
(a) Total Indonesie and Indonesia Petroleum, Ltd.;
(b) Virginia Indonesia Company, Lasmo Sanga-Sanga Limited, OPICOIL
Houston, Inc., Union Texas East Kalimantan Limited, Universe
Gas & Oil Company, Inc. and Virginia International Company;
(c) Unocal Indonesia Company;
(d) Indonesia Petroleum, Ltd.; and
such other entities that may, from time to time, execute a Supply
Agreement with Seller, and any successors and assigns of any of the
aforesaid suppliers who shall have agreed in writing to be bound by all
of the obligations of their respective assignors under the applicable
Supply Agreement with Seller.
<PAGE> 10
1.57 Seller's Transportation Arrangements
The agreements between Seller and Seller's Transporter providing for
the transportation of LNG hereunder, together with any amendment,
modification or supplement thereto.
1.58 Seller's Transporter
Each entity which contracts with Seller to provide transportation of
LNG hereunder.
1.59 Standard Cubic Foot (scf)
The quantity of Natural Gas, free of water vapor, occupying a volume
of one Actual Cubic Foot at a temperature of 60.0 Degrees F and at an
absolute pressure of 14.696 pounds per square inch.
1.60 Substitute LNG Tanker
An LNG tanker, other than the Dedicated LNG Tanker, meeting the
requirements of Section 5.3 and used by Seller for transporting LNG
hereunder.
1.61 Supply Agreement
As defined in Section 3.1.
1.62 Take-or-Pay Quantity
As defined in Section 7.5.
1.63 Taiwanese Tax
As defined in Section 14.3(c).
1.64 Tax Law
As defined in Section 14.3(a).
1.65 Term
As defined in Article 6.
1.66 Transportation Element
As defined in Article 8.1.
1.67 Unloading Port
The port at Yung An, near Kaohsiung, Taiwan, or such other port in
Taiwan as is agreed to between Buyer and Seller.
<PAGE> 11
1.68 U.S.CPI
The United States Consumer Price Index (determined by reference to:
All Urban Consumers (CPI-U); Unadjusted U.S. City Average; All items;
with a base period of 1982-84 = 100) as published by the U.S.
Department of Labor, Bureau of Labor Statistics.
1.69 Used Laytime
As defined in Section 4.5(a).
<PAGE> 12
ARTICLE 2 - SALE AND PURCHASE
Seller agrees to sell and deliver at the Delivery Point, and Buyer agrees to
purchase, receive and pay for, or to pay for if not taken, LNG, in the
quantities, at the price and in accordance with the other terms and conditions
of this Contract.
<PAGE> 13
ARTICLE 3 - SOURCES OF SUPPLY
3.1 Sources of Supply
The Natural Gas to be processed into LNG and sold hereunder is to be
produced from the Gas Supply Area. Seller represents that Seller will
maintain throughout the Term the right and ability to sell all quantities
of LNG to be sold and delivered hereunder. In this connection, Seller
undertakes to execute and deliver to Seller's Suppliers within six (6)
months from the date hereof separate supply agreements with each of
Seller's Suppliers under which agreements each of Seller's Suppliers
respectively and Seller undertake to supply such quantities of Natural Gas
in the aggregate as will be sufficient to permit Seller to meet its
obligations under this Contract ("Supply Agreement"). At such time as the
supply agreements have been executed and delivered Seller will execute and
deliver and cause Seller's Suppliers to execute and deliver a certificate
confirming to Buyer such fact. Notwithstanding any reference to Seller's
Suppliers in this Contract, Seller is fully responsible for performance of
all the obligations of Seller hereunder, and no contractual default of
Seller's Suppliers shall excuse Seller from its full responsibility
hereunder.
3.2 Reserves of Natural Gas
(a) Seller has furnished Buyer with statements, each entitled
"Certificate" and each dated on or prior to December 31, 1994 of
DeGolyer and MacNaughton expressing its estimate of Proved Remaining
Recoverable Reserves of Natural Gas in the Gas Supply Area. Seller
represents that such estimated quantity is in excess of Seller's Gas
Supply Obligation as of the date hereof. Hereafter and throughout the
Term, before committing additional Natural Gas from the Gas Supply
Area to sale or other utilization, Seller shall secure from an
independent petroleum engineering consultant firm of recognized
standing in the petroleum industry, qualified by reputation and
experience in estimating reserves of oil and Natural Gas in subsurface
reservoirs, the written statement (the "Certificate") of such firm
expressing its estimate of Proved Remaining Recoverable Reserves of
Natural Gas in the Gas Supply Area in an amount at least equal to
Seller's Gas Supply Obligation. Seller shall provide Buyer with copies
of each Certificate of such independent petroleum engineering
consultant firm on which Seller relies in making any such commitment
for supply of Natural Gas from the Gas Supply Area. Seller shall also
furnish allsupporting documentation provided by such independent
petroleum engineering consultant firm in connection with the issuance
of such Certificate.
<PAGE> 14
(b) If, during the Term hereof, Seller obtains information from its
activities (including the activities of Seller's Suppliers) in
operating fields in the Gas Supply Area which indicates unforeseen
adverse changes in the Proved Remaining Recoverable Reserves of
Natural Gas in the Gas Supply Area, Seller will promptly inform Buyer
of such situation and will further inform Buyer of any measures which
Seller may be required to take in order to fulfill its obligations
under this Contract.
<PAGE> 15
ARTICLE 4 - TRANSPORTATION AND UNLOADING
4.1 Transportation
(a) At no cost to Buyer, except as otherwise provided herein, Seller shall
be responsible for the transportation from Seller's Facilities to
Buyer's Facilities of the LNG to be sold and delivered hereunder,
using an LNG Tanker.
(b) Seller may use any spare capacity of an LNG Tanker for purposes other
than transporting LNG under this Contract and may schedule the use of
an LNG Tanker to make deliveries hereunder to the extent necessary to
make the best use of such spare capacity.
(c) Seller shall use its best efforts to cause the LNG Tankers to comply
with the regulations of, and to obtain all marine permits required by
Taiwan and other relevant authorities respecting the operation of LNG
Tankers. Buyer shall provide Seller with advice on a timely basis as
to the requirements of Taiwanese regulations and shall use its best
efforts to assist compliance therewith. Buyer shall reimburse to
Seller any and all costs, including costs of modification required to
be made to LNG Tankers, which are incurred by Seller as a result of
the requirements of any governmental authority in Taiwan which differ
from standard international maritime safety or other requirements,
such as those established by the International Maritime Organization,
the U.S. Coast Guard, the Japanese Maritime Agency or internationally
recognized vessel classification societies. Seller agrees to limit
such modifications to the extent strictly needed to comply with
Taiwanese requirements and/or its obligations hereunder and will
consult with Buyer before carrying out such modifications. Seller
further agrees to refund any money paid to it under this Section
4.1(c) if the aforesaid international maritime requirements are
subsequently changed so that they require the same modifications as
were required by Taiwanese authorities.
4.2 Transportation During 1998 and 1999 Fixed Quantity Periods
For the Fixed Quantity Periods 1998 and 1999 the LNG sold hereunder shall
be transported on the Dwiputra or on a Substitute LNG Tanker.
<PAGE> 16
4.3 Notices of LNG Tanker Movements and Characteristics of LNG Cargoes
(a) With respect to each Cargo of LNG to be delivered hereunder, Seller
shall give or shall cause the Master of the LNG Tanker delivering the
same to give to Buyer at Buyer's Facilities the following notices:
(i) a first notice, which shall be sent upon the departure of the
LNG Tanker from the Loading Port and which shall set forth the
time and date that loading was completed, the volume,
expressed in Cubic Meters, of LNG loaded on board the LNG
Tanker and the estimated time of arrival of the LNG Tanker at
the sea buoy of the Unloading Port ("ETA");
(ii) a second notice, which shall be sent forty-eight (48) hours
prior to the ETA;
(iii) a third notice, which shall be sent twenty-four (24) hours
prior to the ETA;
(iv) a final notice, which shall be sent five (5) hours prior to
the ETA; and
(v) a Notice of Readiness, which shall be given at the time
prescribed in Section 4.5(a) below.
(b) Within thirty-six (36) hours after departure of each LNG Tanker from
the Loading Port, Seller shall notify Buyer, for Buyer's information
only, of the following characteristics of the LNG comprised in the
Cargo as determined at the time of loading:
(i) the Gross Heating Value per Standard Cubic Foot;
(ii) the molecular percentage of hydrocarbon components and
nitrogen; and
(iii) average temperature.
The notices referred to in paragraphs (a) and (b) of this Section 4.3 shall
be sent by telex or, if necessary, by radio. The notices referred to in
subparagraphs (iii), (iv) and (v) of paragraph (a) shall be sent by both
telex and radio.
<PAGE> 17
4.4 Obligations of Buyer at Unloading Port
(a) Buyer shall cooperate with the Master of an LNG Tanker directed to the
Unloading Port to ensure the continuous and efficient delivery of LNG
hereunder. Buyer shall provide, in accordance with the provisions of
this Contract, a safe berth for prompt berthing of an LNG Tanker at
Buyer's Facilities and shall operate Buyer's Facilities, or ensure
that they are operated, so as to permit discharge of the Cargo of an
LNG Tanker as quickly as possible. During discharge of each Cargo of
LNG, Buyer shall return to the LNG Tanker natural gas in such
quantities as are necessary for the safe unloading of the LNG at such
rates, pressures and temperatures as may be required by the LNG Tanker
design and commonly accepted operating practice for such LNG Tanker.
The LNG to be sold and delivered hereunder shall be unloaded through
manifold strainers of sixty (60) mesh (or such other mesh as shall be
agreed from time to time by the Parties).
(b) Buyer shall cause to be made available at an Unloading Port such tugs,
fireboats, pilots and other services as are necessary for the purposes
of safety and efficiency and are required by Taiwan authorities.
(c) Seller shall pay, or shall cause Seller's Transporter to pay, all Port
Charges in respect of LNG Tankers at the Unloading Port promptly when
due, provided that Buyer shall reimburse to Seller the amount (if any)
by which such Port Charges exceed the average of those generally
payable for vessels of the same type and size in LNG unloading ports
in Japan.
4.5 Demurrage at Unloading Port
(a) Upon the arrival of an LNG Tanker at an Unloading Port (or off the
Unloading Port if such LNG Tanker is prohibited from approaching or
entering the Unloading Port by applicable safety regulations) the
Master of the LNG Tanker or its agent shall give notice to Buyer or
its agent that such LNG Tanker is ready to discharge LNG, berth or no
berth ("Notice of Readiness"). A Notice of Readiness may be tendered
on any day of the week or any hour of the day. Laytime used in
unloading an LNG Tanker ("Used Laytime") shall begin to count upon the
earlier of (i) four (4) hours from Notice of Readiness, except where
such Notice of Readiness is given when the LNG Tanker is prevented
from berthing because of night berthing restrictions in which case
<PAGE> 18
it shall begin to count from four (4) hours after the sunrise
following such Notice of Readiness, or (ii) the LNG Tanker's being
"all fast" in berth. Used Laytime shall continue to run until
discharge and return lines have been disconnected and the LNG Tanker
is cleared for departure.
(b) "Allowed Laytime" at an Unloading Port shall be twenty-four (24)
consecutive hours extended by any period of delay which is caused by:
(i) reasons attributable to Seller, the LNG Tanker or its Master,
crew, owner or operator, including but not limited to delays
in departure due to quarantine, port regulation or documentary
clearance to the extent so attributable;
(ii) prevention or delay in an LNG Tanker attaining its full design
discharge rate because of the condition of the Cargo;
(iii) Force Majeure;
(iv) occupancy of the berth by another vessel if the LNG Tanker
arrives more than one (1) day after the delivery date
scheduled in the most recent Ninety-Day Schedule without the
consent of Buyer; provided that such period of extension shall
be equal to the lesser of (A) twenty-four (24) hours, or (B)
the time elapsed between Notice of Readiness and the departure
from the berth of such other vessel;
(v) arrival of the LNG Tanker before the delivery date scheduled
in the most recent Ninety-Day Schedule without the consent of
the Buyer; provided that such period of extension shall be
equal to the time elapsed (if any) between commencement of
used laytime and the earlier of (A) 00:00 hours on the
scheduled delivery date, or (B) completion of berthing; or
(vi) "Adverse Weather Conditions", which for purposes hereof means
weather and/or sea conditions actually experienced at the
Unloading Port which are sufficiently severe either: (A) to
prevent all LNG Tankers from proceeding to berth, discharging
or departing from berth in accordance with the weather
standards prescribed in the standard published regulations of
the maritime agency of Taiwan, or (B) to cause an actual
determination by the Master that it is unsafe for the LNG
Tanker to berth, discharge or depart from berth. The
<PAGE> 19
period of delay to an LNG Tanker caused by Adverse Weather
Conditions shall not be considered to extend past the time
during which such Adverse Weather Conditions actually
prevailed except where additional delay is caused by the
occupation of the berth by another LNG Tanker.
(c) In the event Used Laytime exceeds Allowed Laytime (such excess being
herein referred to as "Excess Laytime"), Buyer shall pay to Seller
demurrage determined in accordance with the following formula:
(TE - U.S.$0.12 / MMBTU) x Cargo
-------------------------------- x Days
10
where :
TE = the Transportation Element applicable at the time the
demurrage occurs;
Days = the duration in days (or parts thereof) of the Excess
Laytime.
provided, however, that demurrage shall only be payable under this Section
4.5 (c) to the extent that an event of Excess Laytime ("Event") exceeds a
certain allowance period ("Excess Laytime Allowance"). Such Excess Laytime
Allowance shall be limited to:
(i) six (6) hours per Event; and
(ii) twelve (12) hours in the aggregate for all prior Events during
a period of sixty (60) days ending on the date the Event in
question arises.
Seller shall invoice Buyer for demurrage amounts due under this Section 4.5
at the end of each calendar month, and Buyer shall pay such invoices in
accordance with the terms of Section 10.2.
4.6 Effect of Unloading Port Delays; Excess Boil-Off
(a) Notwithstanding the provisions of Section 11.1, if the Gross
Heating Value of LNG to be delivered hereunder is higher than
the limits set forth in Section 11.1 by reason of boil-off
occurring during a delay in unloading an LNG Tanker of more
than forty-eight (48) hours after
<PAGE> 20
Notice of Readiness has been given, such LNG shall be deemed
to have met the quality specifications of this Contract
regarding the Gross Heating Value.
(b) If an LNG Tanker is delayed in berthing and/or commencement of
unloading for a reason that would not result in an extension
of allowed laytime under Section 4.5(b), and if, as a result
thereof, the commencement of unloading is delayed beyond
thirty (30) hours after Notice of Readiness has been given,
then, for each full hour by which commencement of unloading is
delayed beyond such thirty (30) hour period, Buyer shall pay
Seller an amount, on account of excess boil-off, equal to the
Contract Sales Price multiplied by the number of MMBTUs per
hour by which such boil-off reduces the aggregate number of
BTUs of a Cargo at berth, provided, however, that Buyer shall
not pay for any boil-off which exceeds the boil-off
performance undertaking by Seller's Transporter as agreed
under Seller's Transportation Arrangements for the applicable
LNG Tanker. The hourly BTU reduction rate to be applied for
such purpose shall be determined by actual boil-off experience
as determined at appropriate intervals.
4.7 Non-Utilization Cost
(a) If there is an event of force majeure pursuant to Section 15.1
affecting Buyer's performance of its obligations hereunder
("Buyer Force Majeure") which results in an LNG Tanker being
unutilized and there is an expected Force Majeure Deficiency,
then Buyer shall pay to Seller on account of such non-
utilization an amount in U.S.$ ("Non-Utilization Cost")
determined in accordance with the following formula:
FMD x (TE - U.S. $0.12/MMBTU)
Where:
FMD = the Force Majeure Deficiency resulting from a
Buyer Force Majeure in MMBTUs; and
TE = Transportation Element applicable at the time
such Force Majeure Deficiency occurs.
(b) Any Non-Utilization Cost payable hereunder shall be reduced to
the extent that the LNG Tanker is utilized to deliver to a
third party LNG
<PAGE> 21
which would otherwise have been purchased and received by
Buyer had a Buyer Force Majeure not occured.
(c) Seller shall invoice Buyer for amounts due under this Section
4.7 on a monthly basis and Buyer shall pay such invoice in
accordance with Section 10.2.
<PAGE> 22
ARTICLE 5 - ON-SHORE FACILITIES
5.1 Buyer's Facilities
Buyer has heretofore constructed or will further construct LNG
receiving terminal facilities at an Unloading Port as may be necessary
to fulfill Buyer's obligations to receive LNG hereunder ("Buyer's
Facilities"). Such facilities shall include without limitation, the
following:
(a) Berthing facilities capable of receiving an LNG Tanker having an
overall length of up to three hundred (300) metres, a beam of up to
fifty (50) metres and a draft of up to eleven (11) metres, which the
LNG Tankers can always safely reach, fully laden, and safely depart,
and at which an LNG Tanker can lie safely berthed and discharge safely
afloat at all times;
(b) Unloading facilities capable of receiving LNG at a rate which will
permit the discharging of a Cargo from an LNG Tanker within twelve
(12) hours of pumping time at the full pumping rate specified by the
LNG Tanker design;
(c) A vapor return line system of sufficient capacity to transfer to the
LNG Tanker quantities of natural gas necessary for the safe unloading
of LNG at such rates, pressures and temperatures as may be required by
the LNG Tanker design;
(d) Systems for timely provision of an LNG Tanker with adequate fresh
water, low sulfur fuel oil (until such time as Buyer has bunker oil
available) and diesel oil if necessary;
(e) Facilities allowing access to the LNG Tanker from onshore adequate for
the handling and delivery of ship's stores, provisions and spare parts
to the LNG Tanker;
(f) Shore based tanks and loading lines for liquid nitrogen adequate to
service the LNG Tanker;
(g) LNG storage tanks of adequate capacity to receive and store a Cargo of
LNG upon each scheduled arrival of an LNG Tanker;
<PAGE> 23
(h) Appropriate systems for necessary radio communications with an LNG
Tanker; and
(i) Regasification facilities.
5.2 Seller's Facilities
Seller's facilities shall comprise Natural Gas reservoirs, Natural Gas
production and treatment facilities in and transportation facilities
from the Gas Supply Area including without limitation those facilities
located at Bontang Bay, East Kalimantan for treatment, compression,
liquefaction, processing, transmission, storage, berthing and loading,
and utilities, together with such expansion or modification of the
foregoing as may be necessary, to fulfill its obligations hereunder
("Seller's Facilities").
5.3 Compatibility of Buyer's Facilities and LNG Tankers
(a) Seller shall cause the LNG Tankers to be compatible with Buyer's
Facilities existing as of the effective date of this Contract.
(b) Buyer shall ensure, at no cost to Seller, that any construction or
modification of Buyer's Facilities after the effective date of this
Contract, in addition to meeting the requirements of Section 5.1, is
compatible with the LNG Tankers.
(c) Seller and Buyer shall consult to determine the most effective manner
to achieve the compatibility referred in (a) and (b) above;
provided, however, that Buyer shall have the right to request
modifications to the LNG Tanker to be carried out entirely at Buyer's
expense and such request shall not be unreasonably refused.
5.4 Fuel, Liquid Nitrogen and Fresh Water
Buyer, at no cost to Seller, shall provide at Buyer's Facilities
adequate systems to supply in a safe and efficient manner the
requirements of an LNG Tanker for low sulphur fuel oil (or, when
available, bunker oil) and diesel oil and shall further arrange for
the supply of the requirements of an LNG Tanker for liquid nitrogen
and fresh water. Subject to reasonable advance notice (not in any
event to be less than seven (7) days) prior to arrival of an LNG
Tanker, Buyer shall at all times during the term of this Contract
cause adequate supplies of such products to meet the requirements of
an LNG Tanker to be available for
<PAGE> 24
sale at Buyer's Facilities on the terms and conditions generally
prevailing for long-term contracts for such items in ports in Taiwan.
Seller will have at all times throughout the Term the right to
purchase low sulfur fuel oil (thereafter bunker oil at such time it
is available to Buyer) and diesel requirements of the Dedicated Vessel
(and of any Substitute LNG Tanker during the time it is in service
hereunder) from Buyer or its nominee on such generally prevailing
terms and conditions.
<PAGE> 25
ARTICLE 6 - DURATION OF CONTRACT
This Contract shall be effective on the date hereof and shall continue in
effect until the expiration of the parties' respective obligations to sell and
purchase LNG as provided in Article 7 or the earlier termination of this
Contract pursuant to Article 18 ("Term"). The Term may be extended on such
terms and conditions as are agreed between the Parties no later than five (5)
years prior to the expiry of the Term.
<PAGE> 26
ARTICLE 7 - QUANTITIES
7.1 Required Deliveries
During each calendar year specified below (each such period being
called a "Fixed Quantity Period"), Seller shall sell and deliver to
Buyer, and Buyer shall purchase, receive and pay for, or pay for if
not taken, at the Contract Sales Price, the quantity of LNG having a
heating value as specified for such Fixed Quantity Period (each such
quantity being called a "Fixed Quantity") as follows:
<TABLE>
<CAPTION>
FIXED QUANTITY PERIOD FIXED QUANTITIES
(CALENDAR YEAR) (BILLIONS OF BTUS)
--------------- ------------------
<S> <C>
1998 5,187
1999 38,903
2000 88,179
2001-2017 95,500
</TABLE>
The above Fixed Quantities are subject to adjustment as provided in
Section 7.3(a). After giving effect to any such adjustment, the term
"Fixed Quantity" shall mean the applicable Fixed Quantity as so
adjusted, and the respective obligations of Seller to sell and
deliver, and of Buyer to purchase, receive and pay for, or pay for if
not taken, the Fixed Quantity of LNG in any Fixed Quantity Period
shall apply to the applicable Fixed Quantity as so adjusted.
7.2 Deliveries
Within each Fixed Quantity Period, the quantities to be delivered by
Seller and received by Buyer shall be delivered at rates and intervals
and in quantities which are reasonably constant over the course of
such Fixed Quantity Period and give effect to the maintenance,
downtime and shipping schedules provided for in Article 12, so as to
assure, as nearly as possible, continuous full utilization of the LNG
Tankers, an even production rate at Seller's Facilities, and even
rates of deliveries at Buyer's Facilities.
7.3 Buyer's Obligation to Take or Pay
(a) If, during any Fixed Quantity Period, Buyer should fail to
take the full Fixed Quantity applicable thereto, Buyer shall
pay Seller, at the Contract Sales Price in effect as of the
last day of such Fixed Quantity Period, for
<PAGE> 27
the quantities of LNG required to be purchased but which were
not taken by Buyer during such Fixed Quantity Period (any such
quantity deficiency being called a "Quantity Deficiency"),
subject, however, to paragraphs (b), (c) and (d) below and the
following:
(i) if, after taking into account all adjustments
provided for in this Section 7.3 including any
Allowance that has been exercised, there remains a
Quantity Deficiency for Buyer at the end of any Fixed
Quantity Period, Buyer may carry forward and add to
the Fixed Quantity for the next succeeding Fixed
Quantity Period:
(A) the full amount when such Quantity Deficiency
amounts to less than a Cargo; or
(B) any fractional portion of a Cargo when the
Quantity Deficiency exceeds a Cargo.
Amounts so carried forward shall not be included in
such Quantity Deficiency.
(ii) if, at the time an Annual Program is developed under
Section 12.1, it is estimated that Buyer will have a
Quantity Deficiency in the year which is the subject
of such Annual Program in an amount that is less than
a Cargo, Buyer shall have the right to request an
increase in the quantity which Buyer wishes to take
during such subject year in an amount sufficient to
fill up such Cargo (such right being hereinafter
referred to as Buyer's "Round-Up Request"). If Buyer
does not make a Round-Up Request or if Seller does
not accept such Round-Up Request, the non- delivery
of the partial Cargo of LNG shall not constitute a
failure of Seller to make LNG available for sale for
the purpose of Section 7.3(b). No such Round-Up
Request shall, however, operate to increase Buyer's
Fixed Quantity under this Contract. However, Buyer
shall have a take-or-pay obligation in respect of LNG
quantities that have been the subject of a Round-Up
Request which is accepted by Seller; and
(iii) if, at the end of any Fixed Quantity Period, Buyer
has purchased and received quantities of LNG
hereunder in excess of the Fixed Quantity of Buyer
for such Fixed Quantity Period other than Make-Up
LNG, Make-Good LNG, or Restoration Quantities, the
<PAGE> 28
excess shall be applied to reduce the Fixed Quantity
of the next Fixed Quantity Period.
(b) The obligation (set forth in paragraph (a) above) of Buyer to
pay for Fixed Quantities not taken in any Fixed Quantity
Period shall be reduced by the quantity of LNG which Buyer was
unable to purchase because of an event of Force Majeure
affecting either Seller or Buyer or because of Seller's
failure for any other reason to make such quantity available
for sale in accordance with this Contract.
(c) In calculating the quantity of LNG delivered by Seller and
purchased by Buyer for each Fixed Quantity Period, quantities
delivered and purchased within the first five (5) days of the
next Fixed Quantity Period shall be included, provided such
quantities were scheduled in the Annual Program for the Fixed
Quantity Period with respect to which the calculation is being
made.
(d) The obligation of Buyer pursuant to paragraph (a) above to pay
for quantities not taken may be reduced by the exercise of an
allowance as follows ("Allowance") :
(i) Buyer may only exercise an Allowance by delivering
written notice to Seller, as described in Section
7.3(d)(ii). A notice of exercise of an Allowance,
once given, may not be later withdrawn. Provided,
however, that corrections of clerical or arithmetic
errors may be made at any time;
(ii) each notice of exercise of an Allowance shall specify
the quantity of LNG subject to the Allowance. Such
notice shall be given pursuant to Section 12.1 or by
notice to Seller no later than sixty (60) days prior
to the scheduled date of loading of the Cargo to
which the Allowance specified in any such notice
relates;
(iii) no Allowance can be exercised if its exercise would
result in Buyer's aggregate outstanding Allowances
exceeding six decimal four percent (6.4%) of the
Fixed Quantity for the Fixed Quantity Period in which
the Allowance is desired to be exercised. For the
purposes of this Section 7.3(d)(iii), and subject to
the provisions of Section 7.3(d)(viii), an Allowance,
or portion thereof, shall be deemed outstanding until
either Make-Good LNG is taken
<PAGE> 29
pursuant to Section 7.3(d)(iv), or payment is made
pursuant to Section 7.3(d)(vi);
(iv) each Allowance shall be made good in full (even if it
amounts to a fractional portion of a Cargo) by the
purchase of an equal quantity of LNG in excess of
Fixed Quantities ("Make-Good LNG") within a period
commencing January 1 of the year following the Fixed
Quantity Period in relation to which such Allowance
was exercised and ending with the earlier of the
expiration of five (5) calendar years or March 31,
2018 ("Allowance Restoration Period"). Any Make-Good
LNG purchased after the expiration of the last Fixed
Quantity Period but prior to March 31, 2018 shall be
paid for at the LNG Element in effect as of the date
of delivery plus the actual transportation costs
incurred in delivering the Make-Good LNG. Buyer may
not satisfy a Make- Good Obligation or any part
thereof during a Fixed Quantity Period until it shall
first have taken its Fixed Quantity for such Fixed
Quantity Period. If Buyer has more than one Allowance
outstanding, the Make-Good Obligations in respect
thereof shall be satisfied in the same chronological
order in which such Allowances were exercised;
(v) every request for Make-Good LNG, shall specify the
Allowance to which such request relates;
(vi) if, at the expiration of the Allowance Restoration
Period, a Make-Good Obligation has not been satisfied
in full, Buyer pursuant to Section 7.3(d)(iv) shall
pay Seller for any unsatisfied portion of the
Make-Good Obligation at the Contract Sales Price
(reduced to exclude that portion of the
Transportation Element related to voyage costs) in
effect as of the last day of such Allowance
Restoration Period. Buyer shall have the right to
request Make-Up LNG pursuant to Section 7.5 with
respect to any such payment;
(vii) Seller shall not be obligated to reserve any LNG
production or shipping capacity for the purposes of
permitting Buyer to satisfy Make-Good Obligations;
and
(viii) in the event that Buyer requests quantities of LNG to
satisfy a Make-Good Obligation pursuant to Section
7.3(d)(v) which Seller
<PAGE> 30
is unable to make available for any reason, including
Force Majeure, the following provisions shall apply:
(A) Buyer shall be relieved from the obligation
pursuant to subparagraph (vi) to pay for such
requested quantity as of the expiration of
the Allowance Restoration Period relating
thereto, except in the case where Section
7.3(d)(viii)(C) requires such payment;
(B) such requested quantities shall be deemed not
outstanding for the purposes of Section
7.3(d)(i) until Seller shall (whether during
or after the Allowance Restoration Period)
have offered the same to Buyer but shall then
be outstanding if Buyer does not accept such
offer; any change in the quantity outstanding
due to a failure to accept such an offer
shall not result in an acceleration of any
then outstanding Make-Good Obligations; and
(C) such requested quantities shall be scheduled
for delivery at any time prior to the
expiration of the last Fixed Quantity Period
as mutually agreed by Seller and Buyer. If
such requested quantities have not been
scheduled as of the end of the last Fixed
Quantity Period and should Seller be unable
to deliver such requested quantities during
the three (3) months following the last Fixed
Quantity Period, Buyer shall have no further
obligation in respect thereof. If Seller
gives Buyer reasonable notice that such
requested quantities are available during
such three-month period but Buyer does not
take such quantities, Buyer shall then make
the payment required under Section
7.3(d)(vi).
7.4 Force Majeure Allocation
(a) Whenever deliveries of LNG by Seller under this Contract must
be reduced by reason of an event or circumstance of Force
Majeure affecting Seller's Facilities an allocation of
quantities then available for sale at the Seller's Facilities
will be made between Buyer and other purchasers of LNG from
Seller's Facilities. At such times, the total quantities
available for sale from Seller's Facilities shall be allocated
among the purchasers therefrom (including Buyer) pro rata in
the ratio of their respective quantities which are eligible
for allocation as provided
<PAGE> 31
below. The quantities eligible for such allocation shall, as
to Buyer, be the portion of the Fixed Quantities to be
purchased hereunder during the period of such Force Majeure
and, as to other purchasers, be those fixed or contract
quantities of LNG which are committed for sale from Seller's
Facilities during the period of such Force Majeure in
satisfaction of Seller's contracts with other purchasers which
provide for sales of LNG over a term of at least fifteen (15)
years.
(b) If such an event of Force Majeure does not preclude full
production and loading of all Fixed Quantities under the
allocation formula described in paragraph (a) above, but is of
such an extent as to prevent Seller from producing and loading
all Make-Up LNG, Make-Good LNG and Restoration Quantities
scheduled for delivery from Seller's Facilities to Buyer and
equivalent quantities for the same purposes scheduled for
delivery from Seller's Facilities to other purchasers under
LNG sales contracts providing for deliveries over a term of at
least fifteen (15) years, quantities of such LNG as are
available shall be allocated between Buyer and such other
purchasers in proportion to the respective quantities so
scheduled.
(c) Whenever deliveries of LNG by Buyer under this Contract must
be reduced by reason of a Buyer Force Majeure, an allocation
of quantities then able to be received at Buyer's Facilities
will be made between Seller and other suppliers of LNG to
Buyer. At such times, the total quantities able to be
received by Buyer's Facilities shall be allocated among the
suppliers therefrom (including Seller) pro rata in the ratio
of their respective quantities which are eligible for
allocation as provided below. The quantities eligible for
such allocation shall, as to Seller, be the portion of the
Fixed Quantities to be sold hereunder during the period of
such Force Majeure and, as to other suppliers, be those fixed
or contract quantities of LNG which are committed for sale to
Buyer during the period of such Force Majeure in satisfaction
of Buyer's contracts with other suppliers which provide for
sales of LNG to Buyer over a term of at least fifteen (15)
years.
7.5 Take-or-Pay Make-Up
If, pursuant to Section 7.3(a) or Section 7.3(d)(vi), Buyer shall have
paid for any quantity of LNG which was not taken by Buyer
("Take-or-Pay Quantity"), then, in any subsequent year, Buyer may
purchase up to an equal quantity of LNG from Seller as make-up LNG
("Make-Up LNG") (to the extent not
<PAGE> 32
previously made up). Buyer may request Make-Up LNG by giving written
notice to Seller as provided in Section 12.1. If, during any year for
which Make-Up LNG has been requested, (i) Seller has uncommitted
quantities of LNG available for such purpose, (ii) Seller has
available LNG Tanker capacity which may be used to transport such
Make-Up LNG, and (iii) Buyer shall have first taken and paid for the
Fixed Quantity for such year, then Seller shall sell and deliver to
Buyer the quantity of Make-Up LNG requested; provided, however, that
after the expiration of three (3) months following the end of the last
Fixed Quantity Period such Make-Up LNG shall only be made available if
either Seller has at the time uncommitted shipping capacity available
for the purpose or Buyer provides transportation. Buyer's right to
purchase Make-Up LNG under this Section 7.5 shall expire on December
31, 2018 unless Buyer shall have requested Make-Up LNG during the year
2017 or by January 15, 2018 pursuant to Section 12.2 and Seller shall
have had insufficient uncommitted LNG to meet such request. In such
circumstances, the parties shall consult to agree upon a deferred
schedule for Buyer to take delivery of any outstanding balance of
Take-or-Pay Quantity not made up by December 31, 2018. Buyer shall pay
for Make-Up LNG at the Contract Sales Price in effect as of the date
of delivery, reduced by the amount previously paid on account of all
or that part of the Take-or-Pay Quantity being made up by such sale;
provided, however, that any Make-Up LNG delivered after the end of the
last Fixed Quantity Period shall be paid for at the LNG Element in
effect as of the date of delivery (reduced by the amount previously
paid as the LNG Element on account of all or that part of the
Take-or-Pay Quantity being made up by such sale) plus the actual
transportation costs incurred in delivering the Make-Up LNG.
Take-or-Pay Quantities shall be made up, and prior payments applicable
thereto applied, in the same chronological order in which such
quantities accrued.
7.6 Force Majeure Deficiency
(a) If, during any Fixed Quantity Period or Fixed Quantity
Periods, all or any portion of the Fixed Quantity of LNG
required to be taken by Buyer therein is not delivered by
Seller or taken by Buyer by reason of Force Majeure (any such
quantity not taken for such reason being called a "Force
Majeure Deficiency"), the Parties shall each make best efforts
to restore the Force Majeure Deficiency in full by Seller
selling and Buyer purchasing such quantities of LNG prior to
the expiration of the last Fixed Quantity Period. In the event
that, despite such best efforts, Seller fails to deliver or
Buyer fails to take delivery of the outstanding Restoration
Quantities by the end of 2017, then any obligation of Seller
<PAGE> 33
to deliver and Buyer to take delivery of such Restoration
Quantities shall cease on such date. The quantities to be
restored ("Restoration Quantities") will be scheduled for
delivery pursuant to Article 12 at the mutual convenience of
the Parties. As between a Force Majeure Deficiency resulting
from Force Majeure affecting Seller and a Force Majeure
Deficiency resulting from a Buyer Force Majeure, the
Restoration Quantities applicable thereto shall be scheduled
in the chronological order in which the Force Majeure events
arose. Buyer shall pay for Restoration Quantities at the
Contract Sales Price in effect as of the date of delivery. In
the case of Restoration Quantities arising from a Buyer Force
Majeure, that part of the invoice relating to the
Transportation Element for the quantities being restored will
be reduced by the amount of any Non-Utilization Cost
previously paid under Section 4.7 in respect of such
quantities.
(b) If a Buyer Force Majeure causes a reduction in deliveries of
LNG and if Seller sells to third parties quantities of LNG
which Buyer is unable to purchase, then the Force Majeure
Deficiency shall be reduced by the amount, if any, that
Seller's Gas Supply Obligation (including amounts so sold to
third parties) exceeds the estimate of Proved Remaining
Recoverable Reserves stated in the most recent Certificate as
a result of such sales.
7.7 Allocation for Make-Good LNG, Make-Up LNG and Restoration Quantities
Whenever Make-Good LNG is requested under Section 7.3(d), Make-Up LNG
is requested under Section 7.5 and/or Restoration Quantities are
requested under Section 7.6(a) by Buyer and quantities are requested
for similar purposes by other purchasers from Seller's Facilities
under contracts which provide for sales of LNG over a term of at least
fifteen (15) years, and uncommitted quantities of LNG are not
available from Seller's Facilities to meet all such requests, then the
quantities of LNG which are available from Seller's Facilities for
such purposes shall be allocated, as between Buyer on the one hand and
such other purchasers on the other hand, based on the proportion of
the contract quantities of each requesting purchaser to the total of
the contract quantities of all of the requesting purchasers.
<PAGE> 34
7.8 Order of Priority of Make-Good LNG, Make-Up LNG and Restoration
Quantities
Make-Good LNG requested under Section 7.3(d) and Make-Up LNG requested
under Section 7.5 and Restoration Quantities under Section 7.6(a)
shall be delivered and taken in the following order:
(i) Make-Up LNG;
(ii) Make-Good LNG; and
(iii) Restoration Quantities.
Provided, however, that Buyer and Seller may agree from time to time
to alter the order of the foregoing for a specific purpose and period
of time, and after each such period the above order of priority shall
be restored.
<PAGE> 35
ARTICLE 8 - CONTRACT SALES PRICE
8.1 Formula Calculation of Price
The contract sales price applicable to the quantities of LNG to be
sold and delivered at the Delivery Point and to any quantities of LNG
required to be taken but which are not taken and are required to be
paid for by Buyer hereunder, expressed in United States Dollars per
million British Thermal Units (U.S.$/MMBTU) ("Contract Sales Price"),
shall comprise an LNG element ("LNG Element") and a transportation
element ("Transportation Element") and shall be determined and
adjusted from time to time in accordance with the provisions of this
Article 8. The Contract Sales Price to be applied to the BTUs
comprising each Cargo shall be that Contract Sales Price in effect as
of the date of completion of unloading of such Cargo.
8.2 LNG Element
(a) The LNG Element included in the Contract Sales Price shall be
calculated according to the following formula:
9 A 1 U.S.CPIn
LE = --- (Po x ----------) + --- (Po' x --------) + C
10 U.S.$18.00 10 U.S.CPIo
where:
LE = the LNG Element (expressed in U.S.$/MMBTU);
Po = U.S.$3.06/MMBTU;
A = the arithmetic average of the realized export prices
per barrel in U.S. Dollars, f.o.b. Indonesia, of all
field classifications of Indonesian crude oils then
being sold and exported by PERTAMINA, except premiums
and except such prices for spot sales;
Po' = U.S.$ 3.24/MMBTU;
U.S.CPIn = in respect of the applicable calendar year, the
average of the monthly values of U.S.CPI for the
twelve-month period commencing with the month of
November, fourteen (14) months prior to the beginning
of the applicable calendar year, and ending
<PAGE> 36
with the month of October, three (3) months prior to
the commencement of the applicable calendar year;
U.S.CPIo = 143.8, being the arithmetic average of the monthly
values of U.S.CPI for the twelve-month period,
November 1992 through October 1993; and
C = U.S.$0.012/MMBTU.
(b) An adjustment of the LNG Element to reflect any change in U.S.CPI
shall be made on and shall be effective as of January 1 of each
calendar year, and further adjustments of the LNG Element shall be
made as of each effective date on which:
(i) the realized export prices of more than one of the field
classifications of Indonesian crude oils sold by PERTAMINA
shall have changed from the respective prices therefor
included in the last preceding determination of "A" made
pursuant to Section 8.2(a); or
(ii) two or more field classifications of such crude oils shall
have been added to or deleted from the crude oils being sold
by PERTAMINA since the date of the last preceding
determination of "A" made pursuant to Section 8.2(a).
Procedures for verifying changes in the realized export prices of all
Indonesian crude oils and for determining the effective date of any
adjustment of the LNG Element shall be separately agreed upon by the
Parties.
(c) The Parties shall agree separate procedures for handling corrections,
revisions or changes in the calculation of U.S.CPI. It is agreed that
if at any time the U.S. Department of Labor, Bureau of Labor
Statistics discontinues publishing a report on U.S.CPI values, then
the Parties shall agree upon an index method that reflects inflation
in the United States of America's consumer prices to replace the
discontinued U.S.CPI report.
<PAGE> 37
8.3 Transportation Element for Fixed Quantity Periods beginning in 2000
The Transportation Element to be included in the Contract Sales Price
shall be determined on, and with effect from, January 1, of each
calendar year, in accordance with the following formula (expressed in
U.S.$/MMBTU):
TE = 0.58 x (1.025)n
where: n = 1 on January 1, 1995 and one higher whole
number on each subsequent January 1.
TE = the Transportation Element expressed in
U.S.$/MMBTU for the Fixed Quantity Periods
beginning in 2000.
8.4 Transportation Element for 1998 and 1999 Fixed Quantity Periods
Without prejudice to any other provisions of this Contract, the
provisions of Section 8.3 shall not apply to determine the
Transportation Element to be included in the Contract Sales Price for
1998 and 1999 Fixed Quantities. The Transportation Element to be
included in the Contract Sales Price for 1998 and 1999 Fixed
Quantities shall be determined on, and with effect from, January 1 of
each such year, in accordance with the following formula (expressed in
U.S.$/MMBTU):
TE = 0.58 x (1.025)n
where: n = 1 on January 1, 1995 and one higher whole
number on each subsequent January 1.
TE = the Transportation Element expressed in
U.S.$/MMBTU for the Fixed Quantity Periods
1998 and 1999.
<PAGE> 38
ARTICLE 9 - TRANSFER OF TITLE
The LNG to be sold by Seller and purchased by Buyer hereunder shall be
delivered to Buyer at the Delivery Point. Delivery shall be deemed completed
and title and risk of loss shall pass from Seller to Buyer as the LNG reaches
the Delivery Point.
<PAGE> 39
ARTICLE 10 - INVOICES AND PAYMENT
10.1 Invoice and Cargo Documents
(a) Promptly after completion of unloading of an LNG Tanker,
Seller, or its representative, shall furnish to Buyer, or its
representative, a certificate of volume unloaded together with
such other documents concerning the cargo as may be reasonably
requested by Buyer for the purpose of Taiwan customs
clearance. Buyer shall complete a laboratory analysis pursuant
to Section 13.7 to determine quality and BTU content of the
LNG as soon as possible but not later than forty-eight (48)
hours after the completion of unloading and shall promptly
furnish to Seller or its representative a certificate with
respect thereto by telex, telegram or facsimile or by other
agreed means of electronic communication.
(b) (i) Promptly upon completion of such analysis, Seller or
its representative shall furnish by telex, telegram,
or facsimile or by other agreed means of electronic
communication to Buyer an invoice, stated in U.S.
Dollars, in the amount of the Contract Sales Price
for the number of BTUs delivered; and
(ii) At the same time Seller shall send to Buyer a hard
copy of the invoice together with relevant documents
setting forth the basis for the calculation thereof.
(c) If Buyer has not completed the above mentioned quality and BTU
analysis within the forty-eight (48) hour period mentioned
above, Seller may furnish a provisional commercial invoice
based upon the typical BTU content and typical mole
composition analysis of LNG then being delivered to Buyer, and
such provisional invoice shall be payable on the due date
specified in Section 10.3 subject only to any later adjusting
payment which may be called for when the aforesaid analysis
has been completed.
10.2 Other Invoices
Any amount (other than an amount provided for in Section 10.1) due
from one Party to the other, including, without limitation, amounts
payable pursuant to Section 7.3(a) (on account of Fixed Quantities of
LNG required to be purchased but which were not taken by Buyer) and
Section 7.3(d)(vi), then the Party to whom such moneys are owed shall
furnish an invoice therefor together with
<PAGE> 40
relevant supporting documents showing the basis for the calculation
thereof. The procedure set forth in Section 10.1(b) for sending an
invoice by telex, telegram, or facsimile or by other agreed means of
electronic communication shall be followed. Such invoices shall be
paid in accordance with Section 10.3(b).
10.3 Invoice Due Dates, etc.
(a) Each invoice for LNG delivered to Buyer referred to in Section
10.1 shall become due and payable by Buyer on the eighth (8th)
Business Day in Taiwan after the date on which the invoice has
been received by Buyer in Taiwan under Section 10.1(b)(i).
(b) Each invoice sent pursuant to Section 10.2 shall become due
and payable by the Party receiving the invoice within twenty
(20) calendar days after the date of receipt of such invoice.
(c) Invoices sent by telex shall be deemed received upon receipt
of the addressee's answerback to conclude transmission and in
the case of facsimile, when the addressee acknowledges receipt
of a legible invoice. The Parties shall send invoices
hereunder by telex whenever possible.
(d) If any invoice to Buyer has a due date that is not a Business
Day in Taiwan, such invoice shall become due and payable on
the next day which is a Business Day in Taiwan.
(e) If any invoice to Seller has a due date that is not a Business
Day in Indonesia, such invoice shall become due and payable on
the next day which is a Business Day in Indonesia.
(f) In the event the full amount of any invoice is not paid when
due, any unpaid amount thereof shall bear interest from the
due date until paid, at an interest rate, compounded annually,
two percent (2%) greater than the Prime Rate in effect from
time to time during the period of delinquency. Such interest
rate shall be adjusted up or down, as the case may be, to
reflect any changes in the Prime Rate as of the dates of such
changes in the Prime Rate.
<PAGE> 41
10.4 Payment
(a) Buyer shall pay, or cause to be paid, in U.S. Dollars all
amounts which become due and payable by Buyer pursuant to any
invoice issued hereunder to a bank account or accounts in the
United States to be designated by Seller. Buyer shall not be
responsible for such bank's disbursement of amounts remitted
by Buyer to such bank, and Buyer's deposit in immediately
available funds of the full amount of each invoice with such
bank shall constitute full discharge and satisfaction of the
obligations hereunder for which such amounts were remitted.
Each payment by Buyer of any amount owing hereunder shall be
in the full amount due without reduction or offset for any
reason, including, without limitation, taxes in Taiwan,
exchange charges or bank transfer charges.
(b) Transfer of funds to the bank in the United States, effected
from Taiwan before the close of business in Taiwan on or
before the due date of any invoice, shall be deemed timely
payment notwithstanding that such United States bank cannot
credit such transfer as ready funds for a period of up to
thirteen (13) hours by reason of the time difference between
Taiwan and the United States or for one or more days which are
not banking days in the United States.
(c) Seller shall pay, or cause to be paid, in U.S. Dollars the
amounts which become due and payable by Seller pursuant to a
Section 10.2 invoice to an account with a bank designated by
Buyer. Seller shall not be responsible for the designated
bank's disbursement of funds by Seller to Buyer pursuant to
this paragraph (c).
10.5 Seller's Rights Upon Buyer's Failure to Make Payment
If payment of any invoice for quantities of LNG delivered hereunder or
for Fixed Quantities of LNG not taken and for which Buyer is obligated
to pay hereunder is not made within thirty (30) days after the due
date thereof, Seller shall be entitled, upon giving thirty (30) days'
written notice to Buyer, to suspend subsequent deliveries to Buyer
until the amount of such invoice and interest thereon has been paid,
and Buyer shall not be entitled to any make-up rights in respect of
such suspended deliveries. Any such suspension shall be without
prejudice to any other rights and remedies of Seller arising hereunder
or by law or otherwise, including the right of Seller to receive
payment of all
<PAGE> 42
obligations and claims which arose or accrued prior to such suspension
or by reason of such default by Buyer.
10.6 Disputed Invoices
In the event of disagreement concerning any invoice, Buyer shall make
provisional payment of the total amount thereof and shall immediately
notify Seller of the reasons for such disagreement, except that:
(i) in the case of obvious error in computation, Buyer shall pay
the correct amount disregarding such error; and
(ii) in the case of any disputed invoice for demurrage incurred at
the Unloading Port, Buyer's provisional payment shall be
ninety percent (90%) thereof or such greater amount as is not
disputed by Buyer.
Invoices may be contested by Buyer or modified by Seller only if,
within a period of ninety (90) days after Buyer's receipt thereof,
Buyer serves on Seller notice questioning their correctness. If no
such notice is served, invoices shall be deemed correct and accepted
by both parties. Promptly after resolution of any dispute as to an
invoice, the amount of any overpayment or underpayment shall be paid
by Seller or Buyer to the other, as the case may be, together with a
late fee on such overpayment or underpayment at the same rate as
provided for in Section 10.3(d) for the period from the due date for
payment of the contested invoice until the date such overpayment or
underpayment is made.
<PAGE> 43
ARTICLE 11 - QUALITY
11.1 Gross Heating Value
The LNG when delivered by Seller to Buyer shall have, in a gaseous
state, a Gross Heating Value of not less than 1100 BTUs per Standard
Cubic Foot and not more than 1160 BTUs per Standard Cubic Foot
determined in accordance with the quality standards and procedures as
provided in Schedule A.
11.2 Components
The LNG delivered by Seller to Buyer shall, in a gaseous state,
contain not less than eighty-five molecular percentage (85 MOL%) of
methane (CH4), and, for the components and substances listed below,
such LNG shall not contain more than the following:
A. Nitrogen (N2), 1.0 MOL %.
B. Butanes (C4) and heavier, 2.00 MOL %.
C. Pentanes (C5) and heavier, 0.10 MOL %.
D. Hydrogen sulfide (H2S), 0.25 grains per 100 Standard Cubic
Feet (0.25 grains/100 scf).
E. Total sulfur content, 1.3 grains per 100 Standard Cubic Feet
(1.3 grains/100 scf).
Although the LNG which Seller delivers to Buyer is permitted to
contain the sulfur concentrations shown in clauses D and E above,
under normal operating conditions at Seller's Facilities, Seller would
expect such concentrations to be materially less. Should any question
regarding quality of the LNG arise, Seller and Buyer shall consult and
cooperate concerning such question.
<PAGE> 44
ARTICLE 12 - PROGRAMMING AND SHIPPING MOVEMENTS
12.1 Annual Program
(a) On or before June 15 preceding each Fixed Quantity Period
Seller shall notify Buyer of the current estimate of the BTU
content of each Cargo to be delivered in such Fixed Quantity
Period based to the extent practicable on recent operating
experience. Not later than ninety (90) days prior to the
beginning of each calendar year, Seller shall give written
notice to Buyer of the anticipated quantities of LNG to be
available for delivery hereunder from Seller's Facilities in
each calendar quarter of the next calendar year, taking into
consideration the projected capacity of Seller's Facilities.
On or before October 15 of each year in which such notice is
given, Buyer shall advise Seller in writing of the quantities
Buyer wishes to take during each calendar quarter of the
following year, specifying the amount of any Make-Up LNG
requested pursuant to Section 7.5, and any Restoration
Quantities in excess of Fixed Quantities requested pursuant to
Section 7.6(a), and, if known by Buyer, any Allowance it
intends to exercise. In addition, by October 15 of each year,
Buyer shall request any Make-Good LNG pursuant to Section
7.3(d)(iv). The Parties shall thereupon consult together
regarding a programming schedule of quantities to be delivered
to Buyer's Facilities during each calendar month during the
following year. Thereafter, Seller shall issue by December 1
of the same year a programming schedule ("Annual Program"),
which shall take into consideration the anticipated capacity
of the Parties' respective facilities, the Coordinated
Maintenance Schedule and the shipping schedules. Such Annual
Program and the Ninety-Day Schedules referred to below (and
any revisions thereof) are intended to assist the Parties in
planning their respective operations during the periods
involved. The content of the Annual Program and Ninety-Day
Schedules shall not reduce the entitlement of any Party during
any Fixed Quantity Period to sell, deliver and be paid for, or
to purchase and receive, as the case may be, the quantities of
LNG required under Article 7 to be sold, delivered and paid
for during such Fixed Quantity Period. The Parties will each
take all appropriate steps to carry out each Annual Program
and Ninety-Day Schedule.
<PAGE> 45
(b) An Annual Program shall be amended to reflect a request for:
(i) Make-Up LNG relating to a Take-or-Pay Quantity paid
for in respect of the immediately preceding year;
(ii) Make-Good LNG relating to an Allowance exercised in
respect of the immediately preceding year; or
(iii) Restoration Quantities relating to a Force Majeure
Deficiency arising in respect of the immediately
preceding year;
provided that the requested LNG and the necessary
transportation are available and such request is received by
Seller not later than January 15 of the year to which such
Annual Program relates.
12.2 Ninety-Day Schedules
Not later than the fifteenth (15th) day of each calendar month, Seller
shall, after discussion with Buyer, deliver to Buyer a three-month
forward plan of delivery ("Ninety-Day Schedule"), which follows the
applicable Annual Program as nearly as practicable and sets forth, by
voyages and the projected dates thereof, the pattern of shipments
forecast for each of the next three (3) calendar months. Each
Ninety-Day Schedule shall reflect all adjustments, if any,
necessitated by deviation from prior Ninety-Day Schedules so as to
maintain as far as practicable the scheduled shipments forecast in the
Annual Program.
12.3 Maintenance and Inspection Coordination
Not later than ninety (90) days prior to the beginning of each
calendar year, the Parties shall consult and agree on a program
designed to coordinate the anticipated scheduled maintenance and
inspection downtime during that calendar year of Buyer's Facilities,
Seller's Facilities, and the LNG Tankers. Such program ("Coordinated
Maintenance Schedule") will be devised so as to minimize the
collective impact of such downtime and maintenance periods on the
continuous delivery of LNG hereunder.
<PAGE> 46
ARTICLE 13 - MEASUREMENTS AND TESTS
13.1 Parties to Supply Devices
Seller shall supply, operate and maintain, or cause to be supplied,
operated and maintained, suitable gauging devices for the LNG tanks
of the LNG Tanker, pressure and temperature measuring devices, and any
other measurement or testing devices which are incorporated in the
structure of LNG tankers or customarily maintained on shipboard.
Buyer shall supply, operate and maintain, or cause to be supplied,
operated and maintained, devices required for collecting samples and
for determining quality and composition of the LNG and any other
measurement or testing devices which are incorporated in land
structures or customarily maintained at LNG unloading facilities.
13.2 Selection of Devices
Such devices shall be chosen by mutual agreement of the Parties and
shall be such as are, at the time of selection, the most accurate and
reliable devices in their practical application. The required degree
of accuracy of such devices selected shall be mutually agreed upon and
verified by the Parties, in advance of their use, and at the request
of either Buyer or Seller such degree of accuracy shall be verified by
an independent surveyor mutually agreed upon by the Parties. In any
event all measuring devices (including those on board an LNG Tanker)
shall comply with the maximum permissible tolerances provided for in
Schedule A Part III.
13.3 Units of Measurement and Calibration
The Parties will cooperate closely in the design, selection, and
acquisition of devices to be used for measurements and tests under
this Article 13 in order that, to the maximum extent possible, all
measurements and tests may be conducted either in Imperial units of
measurement or in S.I. units of measurement. In the event that it
becomes necessary to make measurements and tests using a new system of
units of measurement, the Parties shall establish mutually agreeable
conversion tables, or, if they are unable to agree, such tables may be
established by the procedures provided for resolution of disputes on
measurement and testing in Section 13.11. Measurement devices shall
be calibrated as follows :
<PAGE> 47
<TABLE>
<S> <C> <C>
Measurement Imperial Units S.I. Units
Volume Cubic feet Cubic Meters
Temperature Degrees Fahrenheit Degrees Kelvin or Celsius
Pressure Pounds per square inch Kilo Pascal or millibar
or inches of mercury or mm mercury
Length Feet Meters
Weight Pounds Kilograms
Density Pounds per cubic Kilograms per Cubic
foot Meter
</TABLE>
13.4 Tank Gauge Tables of LNG Tankers
Seller shall provide Buyer, or cause Buyer to be provided, with a
certified copy of tank gauge tables for each LNG tank of each LNG
Tanker verified by a competent impartial authority or authorities
mutually agreed upon by the Parties. Such tables shall include
correction tables for list, trim, tank construction and any other
items requiring such tables for accuracy of gauging. The Parties shall
each have the right to have representatives present at the time each
LNG tank on each LNG Tanker is volumetrically calibrated. If the LNG
tanks of any LNG Tanker suffer distortion of such nature so as to
cause a prudent expert to question reasonably the validity of the tank
gauge tables described herein (or any subsequent calibration provided
for herein), Seller shall cause Seller's Transporter to notify Buyer
and Buyer or Seller may require recalibration of such LNG tanks during
any period when the LNG Tanker is out of service for scheduled
inspection or repairs. Upon recalibration of the LNG tanks of the LNG
Tankers, the same procedures used to provide the original tank gauge
tables will be used to provide revised tank gauge tables based upon
the recalibration data. The calibration and recalibration of LNG
tanks provided for in this Section 13.4 shall constitute the only
calibration required for purposes of this Contract.
13.5 Gauging and Measuring LNG Volumes Delivered
Volumes of LNG delivered pursuant to this Contract shall be determined
by gauging the LNG in the LNG tanks of the LNG Tankers before and
after unloading.
Gauging the liquid in the LNG tanks of the LNG Tankers and measuring
of liquid temperature, vapor temperature and vapor absolute pressure
in each LNG tank, trim and list of the LNG Tankers, and atmospheric
pressure shall be performed, or be caused to be performed, by Seller
before and after unloading.
<PAGE> 48
The first gauging and measurements shall be made immediately before the
commencement of unloading. The second gauging and measurements shall take place
immediately after completion of unloading.
Copies of gauging and measurement records shall be furnished to Buyer.
A. Gauging the Liquid Level of LNG
The level of the LNG in each LNG tank of the LNG Tanker shall be
gauged by means of the gauging device installed in the LNG Tanker for
that purpose. The level of the LNG in each LNG tank of the LNG Tanker
shall be logged and printed on board the LNG Tanker.
B. Determination of Temperature
The temperature of the LNG and of the vapor space in each LNG tank of
the LNG Tanker shall be measured by Seller by means of a sufficient
number of properly located temperature measuring devices, to permit
the determination of average temperatures. Temperatures shall be
logged and printed on board the LNG Tanker.
C. Determination of Pressure
The absolute pressure of the vapor in each LNG tank shall be
determined by means of pressure measuring devices installed in each
LNG tank of the LNG Tanker. The atmospheric pressure shall be
determined and recorded by readings from the standard barometer
installed in the LNG Tanker.
D. Determination of Density
Density of the LNG shall be determined by Seller as mutually agreed
to by the Parties. Initially, the density of the LNG will be computed
by the method described in Schedule A.. Should any improved data, or
method of calculation become available which is acceptable to the
Parties, such improved data, or method shall then be used.
13.6 Samples for Quality Analysis
Representative samples of the LNG delivered shall be obtained, or be
caused to be obtained, in triplicate by Buyer during the time of
unloading and delivery to Buyer. The three (3) samples shall be taken
from an appropriate point on Buyer's receiving line as close as
possible to the unloading flanges and collected in the gaseous state
using the continuous gasification/collection
<PAGE> 49
method agreed by the Parties. In addition Buyer shall obtain spot
samples during unloading. The method and devices for sampling and the
quantity of the samples to be withdrawn, shall be determined by
agreement between the Parties to provide for taking representative and
adequate samples of the LNG delivered.
The samples obtained shall be distributed as follows:
First sample - for use for analysis by Buyer receiving the
LNG shipment.
Second sample - for use of Seller.
Third sample - for retention by Buyer for an agreed period,
not to exceed twenty (20) days, during which
any dispute as to the accuracy of any
analysis shall be raised, in which case the
sample shall be further retained until the
Parties agree to retain it no longer.
If it is not possible for any reason to obtain composite samples by
the continuous gasification/collection method, the composition of the
LNG delivered shall be the arithmetic average of the results obtained
by analyses of the spot samples. If it is not possible to obtain such
spot samples, an analysis of the LNG loaded at the Loading Port, after
adjustment for boil-off measured in respect of the laden voyage, shall
be used to determine the composition of the cargo delivered. For this
purpose, Seller shall utilize devices comparable to those utilized at
Buyer's Facilities and shall employ methods of taking and analyzing
the samples at the Loading Port comparable in accuracy to those
employed at Buyer's Facilities.
13.7 Quality Analysis
The samples provided for in Section 13.6 shall be analyzed, or be
caused to be analyzed, by Buyer on receiving the LNG shipment to
determine the molar fraction of the hydrocarbon and other components
in the sample by gas chromatography in accordance with "G.P.A.
Standard 2261, method of Analysis for Natural Gas and Similar Gaseous
Mixtures by Gas Chromatography", published by G.P.A., current as of
1990. If better standards for analysis are subsequently adopted by
G.P.A. or other recognized competent impartial authority, upon mutual
agreement of the Parties, they shall be substituted for
<PAGE> 50
the standards then in use, but such substitution shall not take place
retroactively.
The spot samples taken as specified in Section 13.6 shall serve the
purpose of fall-back reference in case of failure to obtain a
representative composite sample. The composition of the LNG unloaded
from the LNG Tanker shall be determined in case of such failure in
accordance with the procedure provided for in Section 13.6.
A calibration of the chromatograph or other analytical instrument used
shall be performed by Buyer immediately prior to the analysis of the
sample of LNG delivered.
Buyer shall give advance notice to Seller of the time Buyer intends to
conduct a calibration thereof, and Seller shall have the right to have
a representative present at each such calibration; provided, however,
Buyer shall not be obliged to defer or reschedule any calibration in
order to permit the representative of Seller to be present.
The sample shall be analyzed, or be caused to be analyzed, by Buyer to
determine the concentrations of hydrogen sulfide (H2S) and total
sulfur referred to in Section 11.2 using the methods described as
follows:
- ASTM D 2784-70 Standard Method of Test for Sulfur in Liquefied
Petroleum Cases
If the total sulfur content is less than zero decimal
twenty-five (0.25 ) grains per 100 Standard Cubic Feet, it
shall not be necessary to analyze the sample for hydrogen
sulfide.
- ASTM D 2725-70 Standard Method of Test for Hydrogen Sulfide in
Natural Gas (Methylene Blue Method).
13.8 Operating Procedures
Prior to conducting operations for measurement, gauging and analysis
provided in Sections 13.5, 13.6 and 13.7 the Party responsible for
such operations shall notify the appropriate representatives of the
other Party, allowing such representative reasonable opportunity to be
present for all operations and computations; however, the absence of
the other Party's representative after notification and opportunity to
attend shall not prevent any operations and
<PAGE> 51
computations from being performed. At the request of either Party,
any measurement, gauging and analysis provided for in Sections 13.5,
13.6 and 13.7 shall be witnessed and verified by an independent
surveyor mutually agreed upon by the Parties. The results of such
surveyor's verifications shall be made available promptly to each
party. All records of measurements and the computation results shall
be preserved and available to the Parties for a period of not less
than three (3) years after such measurements and computation. A
procedure for operation of onboard CTMS equipment shall be developed
and mutually agreed during the design phase of the Dedicated LNG
Tanker.
13.9 BTU Quantities Delivered
The quantity of BTUs of LNG delivered from an LNG Tanker shall be
calculated by Seller following the procedures described in this
Section 13.9 and shall be verified by an independent surveyor mutually
agreed upon by the Parties.
A. Determination of Gross Heating Value
The Gross Heating Value of the samples of the LNG shall be
determined by computation, in accordance with the method
described in Schedule A, on the basis of the molecular
composition determined pursuant to Section 13.7 and of the
molecular weights and heating values described in "G.P.A.
Publication 2145" published by G.P.A., current at the time of
computation.
If better constants or improved methods for determination of
heating value are subsequently adopted by G.P.A. or other
recognized competent impartial authority, they shall, upon
mutual agreement of the Parties, be substituted therefor, but
not retroactively. The Gross Heating Value of the
representative sample shall be the conclusive Gross Heating
Value for the purpose of determining quantities of BTUs
delivered.
B. Determination of Volume of LNG Unloaded
The LNG volume in the LNG tanks of the LNG Tanker before and
after unloading shall be determined by gauging as provided in
Section 13.5 on the basis of the tank gauge tables provided
for in Section 13.4. The volume of LNG remaining in the LNG
tanks of the LNG Tanker after unloading shall then be
subtracted from the volume before unloading and the resulting
volume shall be taken as the volume of the LNG delivered from
the LNG Tanker.
<PAGE> 52
If failure of gauging and measuring devices of an LNG Tanker
taking the CTMS operating procedure into consideration should
cause impossibility of determining the LNG volume, the volume
of LNG delivered shall be determined by gauging the liquid
level in Buyer's onshore LNG storage tanks immediately before
and after unloading the LNG Tanker and such volume shall be
increased by adding an estimated LNG volume, agreed upon by
the Parties, for boil-off from such onshore LNG storage tanks
and related pipelines during the unloading of LNG. Buyer shall
provide Seller, or cause Seller to be provided with, a
certified copy of tank gauge tables for each onshore LNG tank
which is to be used for this purpose verified by a competent
impartial authority.
C. Determination of BTU Quantities Delivered
The quantities of BTUs delivered from LNG Tankers shall be computed by
Seller by means of the following formula:
Q = V x D x P - Qr
where:
Q represents the quantity of the LNG delivered in BTUs.
V represents the volume of the LNG unloaded, stated in Cubic
Meters, determined as provided in Section 13.9 B.
D represents the density of the LNG unloaded, stated in
kilograms per Cubic Meter, as determined in accordance with
Schedule A.
P represents the Gross Heating Value of the LNG unloaded, stated
in BTUs per kilogram as determined in accordance with Schedule
A.
Qr represents the quantity in BTUs of the vapor which displaced
the volume of LNG unloaded from the LNG tanks of the LNG
Tanker.
Physical constants, calculation procedures and examples of BTU determination
are provided in Schedule A.
<PAGE> 53
13.10 Verification of Accuracy and Correction for Error
Accuracy of devices used shall be tested and verified in accordance
with a program as recommended by the manufacturer unless superseded by
a mutually agreed schedule at any time, if requested by either Party,
including the request by a Party to verify accuracy of its own
devices. Each Party shall have the right to inspect at any time the
measurement devices installed by the other Party, provided that the
other Party be notified in advance. Testing shall be performed only
when the Parties are represented, or have received adequate advance
notice thereof, using methods recommended by the manufacturer or any
other method agreed to by the Parties. At the request of any Party,
any test shall be witnessed and verified by an independent surveyor
mutually agreed upon by the Parties. Permissible tolerances shall be
as defined in Schedule A. Inaccuracy of a device exceeding the
permissible tolerances shall require correction of previous
recordings, and computations made on the basis of those recordings, to
zero error with respect to any period which is definitely known or
agreed upon by the Parties, as well as adjustment of the device. In
the event that the period of error is neither known nor agreed upon,
corrections shall be made for each delivery made during the last half
of the period since the date of the most recent calibration of the
inaccurate device. However, the provisions of this Section 13.10
shall not be applied to require the modification of any invoice which
has become final pursuant to Section 10.6.
13.11 Disputes
In the event of any dispute concerning the subject matter of this
Article 13, including, but not limited to, disputes over selection of
the type or the accuracy of measuring devices, their calibration, the
result of a measurement, sampling, analysis, computation or method of
calculation, such dispute shall be decided by arbitration pursuant to
Section 16.2.
13.12 Costs and Expenses of Test and Verification
All costs and expenses for testing and verifying Seller's measurement
devices as provided for in this Article 13 shall be borne by Seller,
and all costs and expenses for testing and verifying Buyer's
measurement devices shall be borne by Buyer. The fees and charges of
independent surveyors for measurements and calculations as provided
for in Section 13.8 and 13.9 shall be borne equally by the Parties.
When the services of independent surveyors are required and selected
by mutual agreement pursuant to Section 13.10, then the fees and
charges of such surveyors shall be borne equally by the Parties.
<PAGE> 54
ARTICLE 14 - DUTIES, TAXES AND CHARGES
14.1 Buyer's Burden
Buyer shall pay, bear or reimburse to Seller all taxes, royalties,
duties or other imposts which may be levied in Taiwan in respect of
LNG delivered under this Contract.
14.2 Seller's Burden
Seller shall directly or indirectly pay or bear all taxes, royalties,
duties or other imposts which may be levied in Indonesia in respect of
LNG delivered under this Contract and in respect of LNG Tankers.
14.3 Income Tax
(a) It is the understanding of the parties that Seller will not be
subject to income tax in Taiwan by virtue of the sale of LNG
to Buyer pursuant to this Contract. Further, it is the
understanding of the parties that under the income tax law of
Taiwan, as amended on December 30, 1989 (the "Tax Law"),
Seller will not be subject to income tax in Taiwan unless
Seller conducts its business in Taiwan in such a manner as to
be deemed to be (i) a resident company, (ii) engaged in a
trade or business directly, (iii) maintaining a "permanent
establishment" or (iv) doing business through a "business
agent" (as those terms are defined in the Tax Law).
(b) Seller agrees, at all times during the term of this Contract
and to the extent reasonably practicable, to cooperate in
minimizing its liability for Taiwanese income tax; in
particular Seller agrees to conduct all business and other
activities with or in Taiwan so as not to be deemed to fall
within any of the four (4) categories specified in Section
14.3(a).
(c) If Seller shall become subject to income tax levied or imposed
by the government of Taiwan or any subdivision thereof, or any
government authority in Taiwan, on any revenues, income or
profits (including revenues, income or profits resulting from
payments under this Section 14.3(c)) derived from the sale or
import of LNG under this Contract ("Taiwanese Tax"), Buyer
agrees to indemnify and hold harmless Seller from and against
Taiwanese Tax. The foregoing indemnity shall be reduced by the
full amount of benefit obtained or obtainable by Seller
<PAGE> 55
on its income tax liability in Indonesia, whether as credit or
deduction, attributable to the payment by Seller of Taiwanese
Tax. By way of example, if Seller is assessed U.S.$1,000 of
income tax in Taiwan. which is subject to this indemnity, but
Seller becomes entitled to a reduction of U.S.$300 on its
Indonesian income tax because of such payment, the amount of
the indemnity shall be limited to U.S.$700.
(d) If following the date of this Contract there shall occur any
change in the Tax Law which would result in Taiwanese income
tax being levied on Seller with respect to revenues, income or
profits resulting from the sale or import of LNG hereunder,
Seller shall, upon notice from Buyer, consult with Buyer and
take such action as may be reasonably practicable to limit the
amount of such Taiwanese income tax. Nothing in this Article
14 shall require Seller to take or forego taking any action
which would impair Seller's performance of its obligations or
enjoyment of its benefits under this Contract.
<PAGE> 56
ARTICLE 15 - FORCE MAJEURE
15.1 Events of Force Majeure
Neither Seller nor Buyer shall be liable for any delay or failure in
performance hereunder if and to the extent such delay or failure in
performance results from any of the following events ("Force
Majeure"):
(a) fire, flood, atmospheric disturbance, lightning, storm,
typhoon, tornado, earthquake, landslide, soil erosion,
subsidence, washout or epidemic;
(b) war, riot, civil war, blockade, insurrection, act of public
enemies or civil disturbance;
(c) strike, lockout or other industrial disturbance;
(d) serious accidental damage to or other serious failure of
Seller's Facilities unless such damage or failure is the
result of gross negligence on the part of Seller's management;
(e) serious accidental damage to or other failure of Buyer's
Facilities or the facilities for transporting Natural Gas to
Buyer's Natural Gas distribution systems unless such damage or
failure is the result of gross negligence on the part of
Buyer's management;
(f) the Proved Remaining Recoverable Reserves of Natural Gas in
the Gas Supply Area expressed in the then most recent
Certificate referred to in Section 3.2(a) which can be
economically produced have been fully depleted;
(g) act of government which directly affects the ability of a
party to perform any obligation hereunder other than the
obligation to remit payments as provided in Section 10.4 on
account of LNG delivered and taken or not taken but required
to be paid for under this Contract;
(h) delay in completion and testing of any stage of the expansion
of Seller's Facilities contemplated by Seller in connection
with the performance of this Contract so as to prevent the
same from becoming operational on a continuing basis, which
delay is caused by delay in receiving major items of equipment
or materials from the manufacturer or vendor thereof, provided
that Seller shall have taken all steps reasonably
<PAGE> 57
available to obtain timely delivery of such items including
the placing of purchase orders within such time as was prudent
under then existing circumstances;
(i) delay in completion and testing of the vessel intended to be
used as the Dedicated LNG Tanker for 2000 to 2017 so as to
prevent the same from becoming operational on a continuing
basis, provided that Seller shall have taken all steps which
could reasonably have been expected and which are necessary to
fulfill its responsibility to provide transportation under
this Contract; or
(j) (i) the removal of an LNG Tanker from service due to loss,
accidental damage or other serious failure (unless such loss,
damage or failure is the result of gross negligence on the
part of Seller), or (ii) other unavailability of an LNG
Tanker caused by an event beyond the reasonable control of
Seller provided that Seller shall have taken all steps which
could reasonably have been expected and which are necessary to
fulfill its responsibility to provide transportation under
this Contract.
Nothing herein shall relieve Buyer of its obligation to pay for LNG
delivered or to make any other payment which has become due and
payable under this Contract prior to the occurrence of any of the
events described above.
15.2 Notice, Resumption of Normal Performance, etc.
Immediately upon the occurrence of an event of Force Majeure, the
Party whose performance of its obligations hereunder is affected shall
give notice thereof to the other Party describing such event and the
estimated period during which operations will be suspended or reduced.
The Parties shall exercise reasonable diligence to ensure resumption
of normal performance under this Contract after the occurrence of any
event of Force Majeure (which shall include Seller taking all
reasonable steps to provide alternative transportation in the event of
Force Majeure affecting an LNG Tanker), and, prior to resumption of
normal performance, the Parties shall continue to perform their
obligations under this Contract to the extent not affected by such
event of Force Majeure.
<PAGE> 58
15.3 Settlement of Industrial Disturbances
Settlement of strikes, lockouts or other industrial disturbances shall
be entirely within the discretion of the Party experiencing such
situations and nothing herein shall require such Party to settle
industrial disputes by yielding to demands made on it when it
considers such action inadvisable.
<PAGE> 59
ARTICLE 16 - ARBITRATION
16.1 Arbitration
All disputes arising between the Parties relating to this Contract or
the interpretation or performance hereof shall be finally settled by
arbitration conducted in accordance with the Rules of Arbitration of
the International Chamber of Commerce, effective at the time, by three
(3) arbitrators appointed in accordance with such Rules. Arbitration
shall be conducted in the English language and shall be held at Paris,
France, unless another location is selected by mutual agreement of the
Parties. The award rendered by the arbitrators shall be final and
binding upon the parties concerned.
16.2 Disputes of Technical Nature
Notwithstanding the terms of Section 16.1, if a dispute of a technical
nature arises in connection with the interpretation, performance or
non-performance of any of the provisions of Article 13, the Parties
shall agree upon the appointment of a competent, impartial authority
within ten (10) days of a request by either party for the appointment
of such an authority. Failing such agreement, either Party may submit
the matter for expert resolution to the National Bureau of Standards
of the United States Department of Commerce. All decisions of an
authority acting under this Section 16.2 shall be binding on the
Parties. Expenses incurred in connection with the services of such
authority shall be shared equally by the Parties.
<PAGE> 60
ARTICLE 17 - APPLICABLE LAW
This Contract shall be governed by and interpreted in accordance with the laws
of the State of New York, United States of America. The Parties agree that the
U.N. Convention on Contracts for the International Sale of Goods and the
Convention on the Limitation Period in the International Sale of Goods shall
not apply to this Contract and the respective rights and obligations of the
Parties hereunder.
<PAGE> 61
ARTICLE 18 - AUTHORIZATIONS AND APPROVALS; FINANCING
Seller and Buyer shall use best efforts to obtain all authorizations, approvals
and permissions of national and local governments or other competent
authorities or bodies which are required for performance of this Contract (the
"Authorizations and Approvals"), and will cooperate fully with each other
wherever necessary for this purpose. If, Seller or Buyer should fail to obtain
the Authorizations and Approvals within six (6) months after the execution of
this Contract or should Seller fail to arrange the financing for expansion of
Seller's Facilities by January 1, 1997 (the "Financing"), then such Party shall
promptly notify the other Party upon such failure, and Seller and Buyer shall
consult as to the circumstances pertaining thereto. If, within thirty (30) days
after the date of the aforesaid notice, the Parties have not agreed on a
postponement of the time within which the Authorizations and Approvals shall be
obtained, or Financing arranged then either Seller or Buyer may terminate this
Contract by written notice given at any time prior to the date upon which the
Authorizations and Approvals are obtained or Financing arranged. The same right
of termination and procedures relating thereto shall apply upon the expiration
of any postponement period or periods agreed to between the Parties.
Termination of this Contract shall be without prejudice to any accrued rights
of the Parties arising under this Contract prior to termination.
<PAGE> 62
ARTICLE 19 - CONFIDENTIALITY
No Party to this Contract shall use or communicate to third parties the
contents of this Contract or other confidential information or documents which
may come into the possession of such Party in connection with the performance
of this Contract without the prior agreement of the Party or parties to which
such information or documents are confidential. This restriction shall not
apply to the contents of this Contract, or information or documents, which:
(i) have fallen into the public domain otherwise than through the act or
failure to act of the Party that has obtained them; or
(ii) are communicated to:
(A) any of Seller's Suppliers, or any Affiliate (as defined
below), with the obligation of the receiving person to
maintain confidentiality;
(B) persons participating in the implementation of this project,
such as Seller's Transporter, legal counsel, accountants,
other professional, business or technical consultants and
advisers, underwriters or lenders, with the obligation of the
receiving persons to maintain confidentiality; or
(C) any governmental agency of the Republic of Indonesia or
Taiwan, or having jurisdiction over any of Seller's Suppliers
or any Affiliate or Seller's Transporters, provided that such
agency has authority to require such disclosure, and that such
disclosure is made in accordance with that authority.
As used before, the term "Affiliate" means a company that controls, is
controlled by, or is under common control with, a party to this Contract or any
of Seller's Suppliers.
<PAGE> 63
ARTICLE 20 - NOTICES
All notices and other communications for purposes of this Contract shall be in
writing in English, which shall include transmission by telex, facsimile or
telegraph, except that notices given from LNG Tankers at sea may be by radio
except as otherwise required. Notices and communications shall be directed as
follows :
A. To Seller at the following mail address :
PERUSAHAAN PERTAMBANGAN MINYAK DAN GAS BUMI NEGARA (PERTAMINA)
Attention : General Manager, Gas Marketing Department
P.O. Box 1012 / JKT
Jalan Medan Merdeka Timur No. 1A
Jakarta 10110, Indonesia
and at the following Telegraph, Telex and Facsimile addresses :
Telegraph : PERTAMINA JAKARTA, INDONESIA
Telex : 46471 - 45077 - 44441 - 46552 - 46554 - 45347
PERTAMINA JAKARTA, INDONESIA
Facsimile : 62-21-3458312
B. To Buyer at the following mail address :
CHINESE PETROLEUM CORPORATION
Attention : Director of Supply Division
83 Chung Hwa Road
Taipei, Taiwan
and at the following Telegraph, Telex and Facsimile addresses:
Telegraph : CHINESE PETROLEUM CORPORATION
Chinol Taipei
Taipei, Taiwan
Telex : 11934 SPCHINOL
CHINESE PETROLEUM CORPORATION
Facsimile : 886-2-381-4624
<PAGE> 64
The Parties may designate additional addresses for particular communications as
required from time to time, and may change any addresses, by notice given
thirty (30) days in advance of such additions or changes. Immediately upon
receiving communications by telex, facsimile, telegraph or radio, a Party shall
acknowledge receipt by the same means, and may request a repeat transmittal of
the entire communication or confirmation of particular matters. If the sender
receives no acknowledgment of receipt within twenty-four (24) hours, or
receives a request for repeat transmittal or confirmation, said Party shall
repeat the transmittal or answer the particular request.
<PAGE> 65
ARTICLE 21 - JOINT COORDINATING COMMITTEE
Each of the Parties shall promptly appoint representatives to a joint technical
and operating committee ("Joint Coordinating Committee"), which shall hold its
first meeting within sixty (60) days after the execution of this Contract and
thereafter at such intervals as shall be decided upon by the Joint Coordinating
Committee. The Joint Coordinating Committee and such other technical
representatives as may be designated shall consult together to coordinate plans
(a) relating to additions to or modifications of Seller's Facilities and
Buyer's Facilities to accommodate deliveries hereunder; and (b) relating to LNG
Tankers so as to assure that such facilities and LNG Tankers are compatible for
all purposes and that progress is being made in accordance with the project
timetable agreed to between the Parties. Notwithstanding the foregoing, Buyer
and Seller shall regularly keep the other informed of its progress with the
timely performance of its respective obligations hereunder and in particular
shall immediately inform the other of any significant delay envisaged in its
respective performance.
<PAGE> 66
ARTICLE 22 - MISCELLANEOUS
22.1 Assignment
Neither this Contract nor any rights or obligations hereunder may be
assigned by Buyer without the prior written consent of Seller, or by
Seller without the prior written consent of Buyer. Any such purported
assignment without the aforesaid consent shall be null and void.
22.2 Amendments and Waiver
(a) This Contract cannot be amended, modified, varied or
supplemented except by an instrument in writing signed by the
Parties.
(b) The failure of any Party at any time to require performance of
any provision of this Contract shall not affect its right to
require subsequent performance of such provision. Waiver by
any Party of any breach of any provision hereof shall not
constitute the waiver of any subsequent breach of such
provision. Performance of any condition or obligation to be
performed hereunder shall not be deemed to have been waived or
postponed except by an instrument in writing signed by the
Party who is claimed to have granted such waiver or
postponement.
22.3 Details of Performance
Details necessary for performance of this Contract shall be mutually
agreed upon by Seller and Buyer.
22.4 Scope
This Contract supersedes and replaces any provisions on the same
subject contained in any other agreement, memorandum or the like
between the Parties, whether written or oral, prior to the date of
execution hereof.
22.5 Language of the Contract
This Contract is made and executed in the English language.
<PAGE> 67
22.6 Headings and Subheadings
The headings and subheadings in this Contract are inserted solely for
the sake of convenience and shall not affect the interpretation or
construction of this Contract.
22.7 Counterparts
This Contract shall be executed in identical counterparts, each of
which shall have the force and dignity of an original, and all of
which shall constitute but one and the same Contract.
IN WITNESS WHEREOF, each of the Parties has caused this Contract to be executed
in Jakarta by its duly authorized representative as of the date first above
written.
SELLER: BUYER:
PERUSAHAAN PERTAMBANGAN CHINESE PETROLEUM CORPORATION
MINYAK DAN GAS BUMI
NEGARA (PERTAMINA)
By /s/ UNREADABLE By /s/ UNREADABLE
---------------------- ----------------------
President Director Chairman of the Board of Directors
<PAGE> 68
LNG SALE AND PURCHASE CONTRACT (BADAK VI)
BETWEEN PERTAMINA AND CHINESE PETROLEUM CORPORATION
The following describes Schedule A to the LNG Sales and Purchase Contract
(Badak VI) between Pertamina and Chinese Petroleum Corporation, which is
omitted herein, but will be furnished upon request:
Schedule A - Testing and Methods
Part I - BTU Quantity Determination (setting forth a table of physical
constants and the formulae for LNG density determination, gross heating
value calculation and total BTU's delivered calculation)
Table I - Example of LNG Density Calculation
Table II - Molar Volumes of Individual Components
Table III - Correction C for Volume Reduction of Mixture
Table IV - Example of Gross Heating Value (Mass Basis) Calculation
Part II - Quality Determinations
Part III - Maximum Permissable Tolerances
Part IV - Rounding
In addition, Side Letters, dated October 25, 1995, to the LNG Sales and
Purchase Contract (Badak VI), (regarding force majeure, additional quantities,
mutual incentive sharing and transportation), are omitted herein, but wil be
furnished upon request.
<PAGE> 1
BADIN-II REVISED
PETROLEUM CONCESSION
AGREEMENT
BETWEEN
THE PRESIDENT OF THE ISLAMIC
REPUBLIC OF PAKISTAN
AND
UNION TEXAS PAKISTAN, INC.,
OCCIDENTAL PETROLEUM (PAKISTAN), INC.,
OIL AND GAS DEVELOPMENT CORPORATION
AND
THE FEDERAL GOVERNMENT OF THE ISLAMIC REPUBLIC OF PAKISTAN
[EFFECTIVE JANUARY 22, 1995]
<PAGE> 2
BADIN-II REVISED PETROLEUM CONCESSION
AGREEMENT
TABLE OF CONTENTS
<TABLE>
<CAPTION>
Page
<S> <C>
ARTICLE - I
DEFINITIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
ARTICLE - II
RIGHTS AND LIABILITIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
ARTICLE - III
WORK OBLIGATIONS AND SURRENDER OF LICENCE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
ARTICLE - IV
WORKING INTERESTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
ARTICLE - V
LEASES FOR PETROLEUM DEVELOPMENT AND PRODUCTION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
ARTICLE - VI
ASSIGNMENT, SURRENDER OF AREAS AND TERMINATION
OF AGREEMENT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
ARTICLE - VII
WELLHEAD VALUE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
ARTICLE - VIII
NATURAL GAS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28
ARTICLE - IX
RIGHT OF ACQUISITION OF PETROLEUM . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
ARTICLE - X
DISPOSAL OF PETROLEUM . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32
</TABLE>
(i)
<PAGE> 3
<TABLE>
<S> <C>
ARTICLE - XI
FOREIGN EXCHANGE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33
ARTICLE - XII
IMPORTS AND EXPORTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35
ARTICLE - XIII
TAXATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38
ARTICLE - XIV
FORCE MAJEURE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40
ARTICLE - XV
MANAGEMENT AND OPERATIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41
ARTICLE - XVI
ARBITRATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46
ARTICLE - XVII
REFINERY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48
ARTICLE - XVIII
OTHER MINERALS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49
ARTICLE - XIX
AUDIT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50
ARTICLE - XX
PRODUCTION BONUSES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51
ARTICLE - XXI
INSURANCE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52
ARTICLE - XXII
TRAINING, EMPLOYMENT AND SOCIAL WELFARE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53
ARTICLE - XXIII
DEVELOPMENT FINANCING . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55
ARTICLE - XXIV
PARENT COMPANY GUARANTEE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56
</TABLE>
(ii)
<PAGE> 4
<TABLE>
<S> <C>
ARTICLE - XXV
EFFECTIVENESS AND DURATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57
ARTICLE - XXVI
ROYALTY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 58
ARTICLE - XXVII
MISCELLANEOUS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 60
ANNEXURE - I
MAP OF BADIN-II REVISED AREA
ANNEXURE - I-A
MAP OF BADIN-II REVISED AREA TO BE ATTACHED
ANNEXURE - II
BADIN-II REVISED JOINT OPERATING AGREEMENT
ANNEXURE - III
FORM OF DEVELOPMENT AND PRODUCTION LEASE
ANNEXURE - IV
EXHIBIT A
SRO 367(I)/94 DATED MAY 9, 1994
ANNEXURE - IV
EXHIBIT B
CGO-2/93 DATED MAY 20, 1993
ANNEXURE - IV
EXHIBIT C
SRO 336(I)/94 DATED APRIL 26, 1994
ANNEXURE - IV
EXHIBIT D
LIST OF MACHINERY, EQUIPMENT, MATERIALS,VEHICLES
ACCESSORIES, SPARES, CHEMICALS AND CONSUMABLES ETC.
ANNEXURE - IV
EXHIBIT E
SRO 366 (I)/94 DATED 9TH MAY, 1994
</TABLE>
(iii)
<PAGE> 5
ANNEXURE - IV
EXHIBIT F
CBR'S LETTER C.NO.10(14)/93-ICM&CON DATED JUNE 13, 1994
ANNEXURE - IV
EXHIBIT G
LIST OF COMMISSARY STORES
ANNEXURE - V
PARENT COMPANY GUARANTEE
(iv)
<PAGE> 6
BADIN-II REVISED
PETROLEUM CONCESSION AGREEMENT
THIS AGREEMENT, made and entered into between THE PRESIDENT OF THE ISLAMIC
REPUBLIC OF PAKISTAN (hereinafter referred to as the "President" which term
shall include his successors and assigns); and
UNION TEXAS PAKISTAN, INC., a corporation formed and existing under the laws of
the State of Delaware, U.S.A. and registered in Pakistan under Section 277 of
the Companies Act, 1913 (VII of 1913), having its principal office in Pakistan
at Bahria Complex, 3rd Floor, 24 Moulvi Tamizuddin Khan Road, Karachi-2,
Pakistan (hereinafter referred to as "Union Texas" which term shall include its
successors and assigns); and
OCCIDENTAL PETROLEUM (PAKISTAN), INC., a corporation formed and existing under
the laws of the State of Delaware, U.S.A. and registered in Pakistan under
Section 277 of the Companies Act, 1913 (VII of 1913), having its principal
office in Pakistan at 47-N, Dossal Arcade, Blue Area, Islamabad, Pakistan
(hereinafter referred to as "Occidental" which term shall include its
successors and assigns); and
OIL AND GAS DEVELOPMENT CORPORATION, a statutory corporation established under
the Oil and Gas Development Corporation Ordinance, 1961 (XXXVII of 1961),
having its principal office at Masood Mansion, F-8, Al-Markaz, Islamabad,
Pakistan (hereinafter referred to as "OGDC" which term shall include its
successors and assigns); and
THE FEDERAL GOVERNMENT OF THE ISLAMIC REPUBLIC OF PAKISTAN as a Working
Interest Owner and a party to this Agreement and in its capacity as a Working
Interest Owner (hereinafter referred to as "Government Holdings" which term
shall include its successors and assigns).
WITNESSETH
WHEREAS, the President, Union Texas, Occidental and OGDC are parties to the
Petroleum Concession Agreement dated January 21, 1992, and they desire to amend
that agreement so as to provide for, among other things, the renewal of the
Exploration Licence No.115/Pakistan/90 and the application of the of the
Petroleum Policy 1994 of the Government of Pakistan dated March 1994 (the "1994
Petroleum Policy") to the activities undertaken in accordance with this
Agreement;
[PAGE # ... 1]
<PAGE> 7
WHEREAS, in accordance with the provisions of the 1994 Petroleum Policy the
President, Union Texas, Occidental and OGDC desire to include Government
Holdings as a Working Interest Owner and a party to this Agreement;
WHEREAS, the President has granted to Union Texas, Occidental and OGDC a
renewal of the Exploration Licence No.115/Pakistan/90 as amended hereby,
including Government Holdings as a party thereto, and extend those certain
Petroleum concessions and other rights in and to the Badin-II Revised Area
hereinafter described and as hereinafter more particularly set forth and
reserve unto itself an interest as more particularly described herein;
NOW, THEREFORE, the President, Union Texas, Occidental, OGDC and Government
Holdings do hereby agree as follows:
[PAGE # ... 2]
<PAGE> 8
ARTICLE - I
DEFINITIONS
Whenever used in this Agreement, the following terms shall have the following
meanings:
1.1 "Accounting Procedure" - means Exhibit "A" to the Joint Operating
Agreement.
1.2 "Act" - means the Regulation of Mines and Oilfields and Mineral
Development (Government Control) Act, 1948, as amended and in effect
on the Effective Date.
1.3 "Affiliate" - means a company controlling or controlled by a party to
this Agreement. The term "control", as used in this Article 1.3, shall
mean the right to exercise, directly or indirectly, more than fifty
percent (50%) of the voting rights in the company controlled at its
general meeting.
1.4 "Agreement" - means this Badin-II Revised Petroleum Concession
Agreement effective as of January 22, 1995, among the President and
Union Texas, Occidental, OGDC and Government Holdings.
1.5 "Annexure" - means one of the Annexures annexed to this Agreement, all
of which are hereby made a part hereof.
1.6 "Appraisal Well" - means any additional well drilled with respect to a
Discovery prior to the Commercial Discovery Notice Date.
1.7 "Article" - means an article of this Agreement.
1.8 "Badin-II Revised Area" - means the area covered by the Badin-II
Licence as outlined on the map contained in Annexure I, excluding the
area covered by the leases granted under the Badin-II PCA, and any
portion thereof which may be Surrendered in accordance with this
Agreement. The Badin-II Revised Area will be outlined and more
particularly described in Annexure 1-A which is to be initialled by
the President and the Working Interest Owners and attached hereto as
soon as practicable after the Effective Date.
1.9 "Badin-II Revised Licence" - means the Badin-II Revised Exploration
Licence No. 115/Pakistan/90 effective from the Effective Date, insofar
as it covers the Badin-II Revised Area, as renewed in accordance with
the Rules.
[PAGE # ... 3]
<PAGE> 9
1.10 "Badin-II Revised Voting Interest" - means with respect to the
Badin-II Revised Area and any Lease granted with respect thereto, in
matters relating to (a) Exploration and Appraisal Activities and all
other matters other than Development Activities, five percent (5%) for
Government Holdings, twenty-four percent (24%) for OGDC and
thirty-five and five tenths percent (35.5%) for each of Union Texas
and Occidental, and (b) only Development Activities, the Badin-II
Revised Working Interest of each of Government Holdings, OGDC, Union
Texas and Occidental determined in accordance with the provisions of
Article IV in respect of the Discovery Area with respect to which such
Development Activities are undertaken.
1.11 "Badin-II Revised Working Interest" - means the Working Interest of
each of Union Texas, Occidental, OGDC and Government Holdings, as such
Working Interest may be adjusted from time to time in accordance with
the provisions of Article IV, in respect of the Badin-II Revised Area,
the Badin-II Revised Licence and any Leases that may be granted with
respect thereto.
1.12 "Badin-II PCA" - means the Petroleum Concession Agreement dated
January 21, 1992 among the President, Union Texas, Occidental, and
OGDC.
1.13 "Badin-II Licence" - means Exploration Licence No. 115/Pakistan/90 as
in effect up to the Effective Date and as may be extended pursuant to
Article 3.1(b) of the Badin-II PCA and the Rules.
1.14 "Barrel" - means a quantity of Crude Oil and Condensate equivalent in
volume to forty-two (42) United States Gallons adjusted to sixty (60)
degrees Fahrenheit after correction for basic sediment and water
("BS&W").
1.15 "BOE" - means barrel of oil equivalent.
1.16 "BOE/day" - means barrels of oil equivalent per day. Quantities of
Natural Gas produced and saved shall be converted to a barrel of Crude
Oil equivalent on a BTU basis.
1.17 "BTU" - means a British thermal unit.
1.18 "Calendar Quarter" - means a period of three (3) consecutive months,
according to the Gregorian Calendar, which begins 1 January, 1 April,
1 July or 1 October.
1.19 "Calendar Year" - means the period from 1 January to 31 December, both
inclusive, according to the Gregorian Calendar. The tax year of
Working Interest Owner shall be the period from 1 July to 30 June,
both inclusive, according to the Gregorian Calendar.
[PAGE # ... 4]
<PAGE> 10
1.20 "Commercial Discovery" - means a Discovery of Petroleum either duly
evaluated by one or more Appraisal Wells which Discovery, in the
opinion of the Operating Committee, would justify, on the basis of
technical and economic considerations, its development and would
assure Commercial Production or, which has otherwise been approved by
the Government as commercial under this Agreement.
1.21 "Commercial Discovery Notice Date" - means the date when the Operator
formally notifies the Director General Petroleum Concessions that a
Commercial Discovery has been made.
1.22 "Commercial Production" - means the production of Petroleum of a
quantity and quality which Operator reasonably estimates with the
concurrence of the Government (which concurrence shall not be
unreasonably withheld) to be sufficient, over the relevant period to
cover the costs reasonably estimated to be incurred with respect to
the development and production of that Petroleum.
1.23 "Condensate" - means liquid Petroleum (excluding Crude Oil, NGL and
LPG), produced at the surface by processing or separation from Natural
Gas.
1.24 "Crude Oil" - means all Petroleum other than Natural Gas, Condensate,
LPG, and NGL which at standard atmospheric conditions of pressure and
temperature is in a liquid phase.
1.25 "Date of Commercial Production" - means the date when the Operator
commences, on a regular basis, Commercial Production from a Commercial
Discovery.
1.26 "Development Activities" - means all operations undertaken with
respect to a Discovery Area in accordance with the approved
Development Plan including operations approved by the Operating
Committee after the Commercial Discovery Notice Date with respect to
that Discovery Area.
1.27 "Development Plan" - means the plan submitted to the President for
approval in accordance with Rule 33.
1.28 "Director General Petroleum Concessions or DGPC" - means any officer
or authority appointed by the Government to exercise the powers and
perform the functions of the Director General Petroleum Concessions
under the Rules.
1.29 "Discovery" - means the finding of a deposit of Petroleum not
previously known to have existed which is established by conventional
Petroleum industry testing methods in a significant measure.
[PAGE # ... 5]
<PAGE> 11
1.30 "Discovery Area" - means an area as defined in Rule 2(C) of the Rules.
1.31 "Effective Date" - means 12:00 a.m. on January 22, 1995.
1.32 "Expenditures" - means for purposes other than the assessment of
income tax, expenditures incurred in connection with, or incidental
to, the conduct of Petroleum Operations, whether chargeable to capital
or revenue account, including operating costs, whether or not with
respect to producing wells and other assets or, prepayments made after
the Effective Date, acquired for subsequent use in the Petroleum
Operations. Such Expenditures are more particularly classified and
identified as set forth in the Accounting Procedure.
1.33 "Exploration and Appraisal Activities" - means all operations as
approved by the Operating Committee, including the drilling of
Appraisal Wells, (other than Development Activities) performed in
order to determine the existence of previously unknown Petroleum,
including topographic, geodetic, hydrographic, meteorological and
bathymetric studies and surveys; geological and geophysical studies
and surveys; drilling, testing and evaluation of data from Exploration
Wells and Appraisal Wells; and technical or economic studies
pertaining to any of the foregoing operations.
1.34 "Exploration Well" - means a well which tests a clearly separate
geological entity (be it either structural, stratigraphic,
lithological, or facies of a differing pressure nature) penetrating a
prospective geological interval or intervals prior to that entity
being classified as a Discovery.
1.35 "Government" - means The Federal Government of the Islamic Republic of
Pakistan.
1.36 "Joint Operating Agreement" - means the Badin-II Revised Joint
Operating Agreement attached hereto as Annexure II.
1.37 "Joint Operations" - means all Petroleum Operations that are conducted
by the Operator for all of the Working Interest Owners under the Joint
Operating Agreement.
1.38 "Lease" - means the grant of the exclusive right to perform all
activities in connection with exploration, development, production and
transportation of all Petroleum underlying the surface area covered by
a development and production lease granted in accordance with the
Rules in the Badin-II Revised Area.
1.39 "Licensee" - means Union Texas, Occidental, OGDC and Government
Holdings and their respective successors and assigns.
[PAGE # ... 6]
<PAGE> 12
1.40 "Liquified Petroleum Gas" or "LPG" - means a marketable mixture of
propane and butane separated from Natural Gas by compression,
extraction or other processes and marketed in conformity with the
quality and specifications established by Pakistan Standard
Specifications No. 1705-1976 for Commercial Butane-Propane Mixture as
amended from time to time.
1.41 "Minimum Expenditure" - means with respect to the (i) first Renewal
Period US$1,500,000, (ii) second Renewal Period US$1,500,000, and
(iii) third Renewal Period US$750,000.
1.42 "Minimum Work Program" - means the work described in Article 3.2 of
this Agreement for each Renewal Period undertaken with respect to the
Badin-II Revised Area.
1.43 "Natural Gas" - means all hydrocarbons which at standard atmospheric
conditions of pressure and temperature are in a gaseous phase.
1.44 "Natural Gas Liquids" or "NGL" - means ethane and any higher molecular
hydrocarbons separated from Natural Gas by compression, extraction or
other process, but does not include Condensate, propane or butane
fraction extracted from Natural Gas for the manufacture of LPG.
1.45 "Operating Committee" - means the committee constituted pursuant to
the terms of the this Agreement and the Joint Operating Agreement.
1.46 "Operator" - means the person so designated from time to time pursuant
to the Joint Operating Agreement, which person shall initially be
Union Texas.
1.47 "Optional Interest" - means an amount (not to exceed twenty percent
(20%)) expressed as a percentage of one hundred percent (100%) of the
Working Interests by which Government Holdings has elected to increase
its Working Interest in accordance with Article IV.
1.48 "Petroleum" - means all liquid and gaseous hydrocarbons existing in
their natural condition in the strata, as well as all substances,
including sulphur, produced in association with such hydrocarbons, but
does not include basic sediments and water.
1.49 "Petroleum Operations" - means all Petroleum exploration, prospecting,
developing and producing activities conducted by the Working Interest
Owners under and pursuant to the Badin-II Revised Licence, this
Agreement and the Joint Operating Agreement and include any gas-oil
separation, pressure maintenance, pipeline and other transportation,
Crude Oil storage or other activity necessary to facilitate the
production of Petroleum. Petroleum
[PAGE # ... 7]
<PAGE> 13
Operations do not include the construction or operation of any Crude
Oil refinery.
1.50 "Private Working Interest Owner" - means a Working Interest Owner
other than Government Holdings or any other entity in which the
Government owns more than fifty-one percent (51%) of the shares.
1.51 "Renewal Period" - means a period of twelve (12) months beginning on
the Effective Date and from each anniversary of the Effective Date for
which the President has granted a renewal of the Badin-II Licence as
set out in the Rules.
1.52 "Royalty Petroleum" - means the Petroleum taken in kind by the
Government in payment of the royalty obligation of the Working
Interest Owners as provided in Article XXVI and the Rules.
1.53 "Rules" - means the Pakistan Petroleum (Exploration and Production)
Rules, 1986, including all Schedules, as amended and in effect on the
Effective Date.
1.54 "Share of Expenditures" - means the share of Expenditures for
Exploration and Appraisal Activities of Union Texas, Occidental and
OGDC determined in accordance with Article IV.
1.55 "Surrender" - means the termination of rights with respect to the
whole or any part of the Badin-II Revised Area including the
expiration of rights according to the terms of the Badin-II Revised
Licence, any Lease and this Agreement.
1.56 "Wellhead Value" - means the value for Petroleum as determined in
accordance with the provisions of the Rules and Article VII.
1.57 "Working Interest" - means all or any undivided interest in the
entirety of the Petroleum concession and other rights granted and
obligations and liabilities imposed by this Agreement, the Joint
Operating Agreement, the Badin-II Revised Licence and any Leases,
including the enjoyment of the exclusive right to explore for,
prospect for, develop, produce, own, sell and otherwise dispose of
Petroleum from all or part of the Badin-II Revised Area and which
interest is chargeable with and currently obligated to bear and pay
its proportionate part, except as otherwise provided in Article IV, of
all costs and expenditures (including royalties on production and
rental) incurred by Working Interest Owners in exploring and
prospecting for, drilling, developing, producing, selling and
otherwise disposing of Petroleum from all or part of the Badin-II
Revised Area.
1.58 "Working Interest Owner" - means an entity owning a Working Interest
in the Badin-II Revised Area or any Lease granted with respect
thereto.
[PAGE # ... 8]
<PAGE> 14
ARTICLE - II
RIGHTS AND LIABILITIES
2.1 The President has renewed the Badin-II Licence No.115/Pakistan/90 in
accordance with the Rules as the Badin-II Revised Exploration Licence
No.115/Pakistan/90 and grants to the Licensees effective on the
Effective Date, the rights more particularly described in this
Agreement, including, but not limited to, the exclusive right of being
granted Leases and of conducting or causing to be conducted Petroleum
exploration, prospecting, development and production operations
hereunder and thereunder within the Badin-II Revised Area including
the transportation (whether by pipeline or otherwise), storage,
terminalling, export and sale of Petroleum, subject to the provisions
of this Agreement.
2.2 (a) Union Texas shall act as Operator for the Badin-II Revised
Area subject to the provisions of the Joint Operating
Agreement and no change of the Operator may take place without
the consent of the Government.
(b) The Petroleum Operations, with respect to Badin-II Revised
Area, shall be conducted diligently, and in conformity with
the requirements of the Rules, this Agreement and all
applicable laws and regulations. In the event that the
standards of performance with respect to a particular
Petroleum Operation is not specified in the Rules or
applicable laws and regulations, then any such Petroleum
Operation shall be conducted in accordance with good oilfield
practice.
2.3 This Agreement contemplates Petroleum Operations which will or may
require the construction and operation of temporary or permanent
exploration, prospecting and production facilities (including
pipelines) both within and outside the Badin-II Revised Area. The
President, subject to relevant laws and Rules, agrees to assist the
Operator in carrying out all Petroleum Operations contemplated hereby
including the construction and operation of such facilities and in
obtaining for the Operator and its contractors and sub-contractors
such communication permits (radio, telex, telefax, telephone and PABX,
etc.) work permits, security clearances and aviation permits or
licenses, or other clearances, permits and authorizations as shall be
necessary or convenient in connection with the Petroleum Operations to
be conducted under this Agreement and the Joint Operating Agreement.
[PAGE # ... 9]
<PAGE> 15
2.4 The President shall upon request use his good offices and assist in
acquiring at reasonable cost for the sole account of the Working
Interest Owners any surface rights required by them in carrying out
any Petroleum Operations contemplated hereunder, including, but not
limited to, acquisition of land and terminal facilities together with
the necessary means of communication and transportation between such
facilities and the Badin-II Revised Area.
2.5 The rights, duties, and obligations of the Working Interest Owners in
relation to the President shall be joint and several. Nothing herein
contained shall be construed as creating a partnership or joint
venture of any kind, an association or a trust or a taxable entity or
as imposing upon the Working Interest Owners any partnership duty,
obligation or liability.
[PAGE # ... 10]
<PAGE> 16
ARTICLE - III
WORK OBLIGATIONS AND SURRENDER OF LICENCE
3.1 The renewal of the Badin-II Revised Licence with respect to the
Badin-II Revised Area is valid for a Renewal Period of one year
effective from the Effective Date. The President shall grant in
accordance with Rule 21 of the Rules to the Licensees two (2)
subsequent renewals of the Badin-II Revised Licence.
3.2 As a Minimum Work Program for the renewal of the Badin-II Revised
Licence, the Working Interest Owners shall conduct the work as
specified below:
<TABLE>
<CAPTION>
RENEWAL MINIMUM WORK MINIMUM EXPENDITURE
PERIOD PROGRAM (US DOLLARS)
<S> <C> <C>
First Two (2) Exploration Wells 1,500,000
Second Two (2) Exploration Wells 1,500,000
Third One (1) Exploration Well 750,000
</TABLE>
Four (4) of the Exploration Wells to be drilled in accordance with the
Minimum Work Program shall be drilled to the Lower Cretaceous Upper
Shale Unit of the Lower Goru formation and one of the Exploration
Wells to be drilled in accordance with the Minimum Work Program shall
be drilled through the Jurassic-Cretaceous Sembar Formation to the top
of the Chiltan limestone. The performance of the Minimum Work Program
for each Renewal Period for which the Badin-II Licence is extended is
the unconditional obligation of the Working Interest Owners. The
average estimated cost for an Exploration Well used for purposes of
determining the Minimum Expenditure is US$750,000.
3.3 The Operator shall keep the DGPC informed of the progress of each well
and shall:
a) as soon as possible, make known to the DGPC its proposals for
testing;
b) test potentially productive horizons indicated by wireline
recording;
[PAGE # ... 11]
<PAGE> 17
c) promptly undertake the technical evaluation of the test
results and of all other relevant data and submit the same to
the DGPC as soon as possible.
3.4 The Minimum Expenditures obligations set forth in Article 3.2 shall be
satisfied if the Working Interest Owners fulfil the Minimum Work
Program for any Renewal Period at a lower cost than the Minimum
Expenditures for such Renewal Period.
3.5 If during a Renewal Period any wells in excess of the number of wells
required to be drilled in accordance with the Minimum Work Program for
that Renewal Period are drilled and such excess well or wells fulfil
the requirements for the Minimum Work Program, then such excess wells
may be carried forward and deducted from the Minimum Work Program
required for any succeeding Renewal Period. If for any Renewal Period
a well required to be drilled in accordance with the Minimum Work
Program for that Renewal Period has not been drilled, then the
Licensees shall pay to the Government, as liquidated damages, the AFE
cost, as approved by the Operating Committee, (excluding costs of
testing, completion and surface facilities and equipment) of the well
which was not drilled or, in the event that no AFE has been approved
for such well, US$750,000, shown as the Minimum Expenditure for the
well.
3.6 a) All Exploration Wells drilled by the Working Interest Owners
pursuant to Article 3.2, shall be treated as fulfilment of the
obligation of the Working Interest Owners, if they have been
drilled to the objective formation as provided in Article 3.2.
b) If the Operating Committee is of the opinion that it is
impossible or impractical due to technical difficulties to
satisfactorily complete an Exploration Well to the objective
formation, the Working Interest Owners shall drill a
substitute well within a reasonable time from the abandonment
of such Exploration Well for the purpose of discharging the
Minimum Work Program and the Badin-II Revised Licence shall be
extended in accordance with the Rules for a period of time
equal in length to the time needed for drilling and testing
the substitute well.
3.7 Once the Working Interest Owners have completed the Minimum Work
Program, they shall have no further work obligation with respect to
the Badin-II Revised Licence for any remaining Renewal Period for
which a renewal may be granted.
3.8 At the end of each of the first and second Renewal Period, the Working
Interest Owners shall Surrender an area equal to ten percent (10%) of
the Badin-II Revised Area after excluding the area covered by the
Leases granted or applied
[PAGE # ... 12]
<PAGE> 18
for with respect to the Badin-II Revised Area on or prior to the end
of each such Renewal Period.
3.9 The Badin-II Revised Licence as it relates to any well, the drilling
of which was begun on or prior to the expiration of the Badin-II
Revised Licence, shall continue until the completion of any such well
being drilled. In the event any such well results in a Commercial
Discovery, this Agreement shall continue to apply until the
corresponding Lease has expired. If any such well results in a
Discovery, the procedures as set forth in Article V shall be followed.
[PAGE # ... 13]
<PAGE> 19
ARTICLE - IV
WORKING INTERESTS
4.1 The Badin-II Revised Working Interest of Government Holdings, Union
Texas, Occidental and OGDC shall:
(a) in the Badin-II Revised Area, subject to the further
provisions of this Article 4.1, be:
GOVERNMENT HOLDINGS 5.0%
OGDC 24.0%
UNION TEXAS 35.5%
OCCIDENTAL 35.5%
(b) in any Discovery Area in the Badin-II Revised Area in the
event that Government Holdings exercises its option to
increase its Working Interest in any such Discovery Area in
accordance with Article 4.4 from the Commercial Discovery
Notice Date for that Discovery Area, be:
<TABLE>
<S> <C>
GOVERNMENT HOLDINGS 5.0% plus the Optional Interest
OGDC 24.0%
UNION TEXAS 35.5% less its proportionate
share of the Optional Interest
OCCIDENTAL 35.5% less its proportionate
share of the Optional Interest
</TABLE>
4.2 The Working Interest Owners shall bear and pay for all the
Expenditures incurred by Operator in connection with the performance
of Exploration and Appraisal Activities conducted with respect to the
Badin-II Revised Area and any Leases granted with respect thereto in
accordance with their respective Share of Expenditures. The Share of
Expenditures of Government Holdings, Union Texas, Occidental and OGDC
shall be:
[PAGE # ... 14]
<PAGE> 20
GOVERNMENT HOLDINGS 0.0%
OGDC 24.0%
UNION TEXAS 38.0%
OCCIDENTAL 38.0%
4.3 The Working Interest Owners shall bear and pay for all Expenditures
incurred by the Operator in connection with Development Activities in
accordance with their respective Badin-II Revised Working Interests in
the Discovery Area to which such Development Activities relate as such
Working Interests are determined after giving effect to the provisions
of this Article IV.
4.4 (a) As of the Commercial Discovery Notice Date for each Discovery
Area within the Badin-II Revised Area or any Lease, made
during the term of this Agreement or any such Lease,
Government Holdings shall have the right to increase its five
percent (5%) Working Interest up to a maximum of twenty-five
percent (25%) in that Discovery Area. Government Holdings
shall notify, in writing, the other Working Interest Owners
whether it intends to exercise such right within thirty (30)
days of the date of the approval by the Government of the
Development Plan for such Discovery Area and include in such
notice the Optional Interest.
(b) Union Texas and Occidental, shall in proportion to their
respective Working Interests, promptly assign to Government
Holdings the Optional Interest to be acquired by Government
Holdings, such assignment shall be effective as of the
Commercial Discovery Notice Date for such Discovery Area. The
assignment to Government Holdings by Union Texas and
Occidental of their proportionate share of the Optional
Interest shall not effect a transfer of any of the
Expenditures made by Union Texas or Occidental with respect to
that portion of the Optional Interest assigned to Government
Holdings prior to the Commercial Discovery Notice Date in
accordance with the provisions of this Article 4.4(b).
4.5 (a) Government Holdings shall promptly reimburse, without interest
and subject to adjustment based on audit, Union Texas and
Occidental for their respective Working Interest share of all
Expenditures made with respect to such Discovery Area from the
Commercial Discovery Notice Date to the date on which
Government Holdings exercised its option. The reimbursement
shall be shared by Union Texas and Occidental in proportion to
their respective contributions to the total amount of the
Expenditures to be reimbursed. Reimbursements made pursuant to
this Article 4.5(a) shall be paid in US currency.
[PAGE # ... 15]
<PAGE> 21
(b) The reimbursement by Government Holdings pursuant to this
Article 4.5 shall not be computed as taxable income of the
Working Interest Owners receiving such reimbursement either
for income tax or for capital gains purposes provided that
such Working Interest Owners reduce their claim of total
Expenditures by the amount of the reimbursement received by
each of them. Such reimbursement shall not be subject to any
sales, transfer, or registration tax or similar levy.
[PAGE # ... 16]
<PAGE> 22
ARTICLE - V
LEASES FOR PETROLEUM DEVELOPMENT AND PRODUCTION
5.1 In the event of a Discovery within the Badin-II Revised Area or any
Lease, the Operator shall promptly inform the DGPC in accordance with
Rules 52(a) and (b) of the Rules. The Operator shall, within a
reasonable time, after the Discovery submit to the Operating Committee
a recommendation as to the further activities to be conducted with
respect to that Discovery. The Operator shall within thirty (30) days
after the date on which the Operating Committee determines whether the
Discovery (i) merits the performance of further Exploration and
Appraisal Activities, (ii) is a Commercial Discovery that does not
require the performance of further Exploration and Appraisal
Activities, or (iii) is not a Commercial Discovery and merits no
further activity of any type, deliver written notice to DGPC of such
determination made by the Operating Committee.
In the event that a Working Interest Owner, contrary to the
determination made by the Operating Committee in clause (iii) of
Article 5.1, is of the opinion that a Discovery is a Commercial
Discovery that Working Interest Owner may proceed in accordance with
the provisions of Article 8 of the Joint Operating Agreement to
develop that Discovery. In such event, the Working Interest Owner may
request that the Operator notify the DGPC that such Working Interest
Owner considers the Discovery to be a Commercial Discovery. Upon such
determination made by a Working Interest Owner, the provisions of
Article 8 of the Joint Operating Agreement shall apply to the further
activities conducted with respect to any such Discovery.
5.2 (a) For each Discovery with respect to which the Operator notifies
the DGPC that the Operating Committee has determined that the
Discovery merits the further performance of Exploration and
Appraisal Activities, the Operator shall, within a reasonable
time, submit to the DGPC an appraisal program and budget for
the further Exploration and Appraisal Activities that the
Operating Committee has approved to be performed with respect
to the Discovery. The Working Interest Owners shall, in
accordance with the appraisal program, continue diligently to
appraise the Discovery.
(b) For each Discovery with respect to which the Operator notifies
the DGPC that the Operating Committee has determined that the
Discovery is a Commercial Discovery (whether such
determination has been made after further Exploration and
Appraisal Activities have been undertaken with
[PAGE # ... 17]
<PAGE> 23
respect to that Discovery or the Operating Committee has
determined that the Discovery is Commercial Discovery on the
basis of the initial Exploration Well), the Operator shall
submit to the DGPC a Development Plan for the development of
the Discovery in accordance with this Article V.
5.3 For each Commercial Discovery, the Operator shall, within a reasonable
time, submit an application for grant of a Lease which shall be
accompanied by:
(a) a report on the Commercial Discovery; and
(b) a Development Plan for approval by the Government. The
Government's approval of a Development Plan shall not be
unreasonably withheld and such approval shall be granted
within a reasonable period of time from the date on which the
Development Plan is submitted to the Government.
In the event that the Commercial Discovery is within a Lease
previously granted under this Agreement, then the application for a
grant of a Lease shall state that a new Lease is not required to be
granted and that the Discovery Area is subject to the terms and
conditions of the Lease in which any portion of the Discovery Area is
located. The Development Plan may be a revision of a Development Plan
that had previously been approved by the Government if the Discovery
Area to which such revised Development Plan relates is within a Lease.
5.4 The report on the Commercial Discovery referred to in Article 5.3
shall include, but not be limited to:
(a) the chemical composition, physical properties and quality of
Petroleum discovered;
(b) the thickness and extent of the production strata;
(c) petrophysical properties of the reservoirs;
(d) the productivity indices for wells tested at various rates of
flow;
(e) permeability and porosity of the reservoirs;
(f) the estimated production capacity of the reservoirs; and
[PAGE # ... 18]
<PAGE> 24
(g) economic feasibility studies carried out by or for the
Operator in respect of the Commercial Discovery including an
analysis of prospective cash flows from the Petroleum
Operations which the Operator proposes to undertake.
5.5 The Development Plan referred to in Article 5.3 shall include
particulars of but not be limited to:
(a) proposals for the development and production of the Commercial
Discovery, including possible alternatives and proposals
relating to the disposition of Natural Gas;
(b) proposals relating to the spacing, drilling and completion of
wells, the production and storage installations and transport
and delivery facilities required for the production, storage
and transport of Petroleum. Such proposals will cover:
(i) the estimated number, size and production capacity of
production facilities, if any;
(ii) estimated number of production wells;
(iii) particulars of production equipment and storage
facilities;
(iv) particulars of feasible alternatives for the
transportation of Petroleum including pipelines;
(v) particulars of equipment required for the operations;
(c) the production profiles for Crude Oil and Natural Gas and
other products;
(d) cost estimates of capital and recurring Expenditures;
(e) profitability estimates;
(f) proposals (if any) related to the establishment of processing
facilities and the processing of Petroleum in Pakistan;
(g) safety measures to be adopted in the course of development and
production operations including measures to deal with
emergencies and environmental measures;
[PAGE # ... 19]
<PAGE> 25
(h) a description of the organization in Pakistan, pursuant to
Rule 35 of the Rules;
(i) an estimate of the time required to complete each phase of the
proposed development;
(j) a description of the measures to be taken to ensure compliance
with Rule 61 of the Rules regarding the employment and
training of Pakistani personnel; and
(k) A description of the abandonment plan on termination of
Petroleum rights in accordance with the provisions of Rule 69
of the Rules.
5.6 When the Government has approved, pursuant to Rule 33 of the Rules,
the Development Plan, it shall grant to the Working Interest Owners a
Lease in accordance with Rule 27 of the Rules for the Discovery Area.
5.7 Each Lease shall be granted for an initial term of twenty (20) years.
Upon application from any Working Interest Owner, the President shall
renew the Lease for a period of five (5) years, if Commercial
Production is continuing at the time of the application through a
secondary recovery project or otherwise.
5.8 Each such Lease issued shall be granted in the names (and undivided
Working Interests) of each of the Working Interest Owners that have a
Working Interest in the Discovery Area to which such Lease relates and
shall obligate them in accordance with their respective Badin-II
Revised Working Interests therein.
5.9 The Surrender, at any time of any part of the Badin-II Revised Area
which is covered by any Lease, shall terminate such Lease as to that
portion so Surrendered and shall excuse the performance of any
obligation under such Lease with respect to that portion Surrendered
and any unaccrued obligation provided in the Act, the Rules or this
Agreement with respect to the area Surrendered.
5.10 Not less than ninety (90) days prior to the beginning of each Calendar
Year following the commencement of regular shipments of Crude Oil,
Condensate or Natural Gas, the Operator shall prepare and furnish to
the Government for approval a forecast statement and the basis thereof
setting forth by quarters the total quantity of Crude Oil (by quality,
grade and gravity), Condensate and Natural Gas that the Operator
estimates can be produced, saved and transported hereunder during such
Calendar Year in accordance with good oilfield practices. The
Operator shall endeavour to produce in each Calendar
[PAGE # ... 20]
<PAGE> 26
Year the forecast quantity. The Crude Oil and Condensate shall be run
to storage tanks, constructed, maintained and operated by the Operator
in accordance with the Rules. All Petroleum shall be metered or
otherwise measured in accordance with the Rules.
[PAGE # ... 21]
<PAGE> 27
ARTICLE - VI
ASSIGNMENT, SURRENDER OF AREAS AND TERMINATION OF AGREEMENT
6.1 Subject to this Article VI and in accordance with Rule 8 of the Rules,
no Working Interest Owner shall sell, assign, transfer, convey or
otherwise dispose of all or any part of its rights or Working Interest
under this Agreement, the Badin-II Revised Licence and any Lease
without the prior written consent of the Government.
6.2 Provided that the proposed assignor gives written notice of the
proposed assignment to all Working Interest Owners and further
provided that the Government does not inform the proposed assignor in
writing of the Government's objection thereto (which objection shall
not unreasonably be made) within ninety (90) days after such notice is
received, such consent shall be deemed to have been given.
6.3 To the extent of any such assignment, the rights and privileges
granted to and the obligations assumed by the assignor under and
pursuant to this Agreement, the Badin-II Revised Licence and any Lease
(to the extent of such assignment) shall inure to the benefit of and
be binding upon the assignee provided that in the case of an
assignment to an Affiliate, the assignor shall remain bound by such
obligations unless released in writing by the Government and all other
Working Interest Owners.
6.4 Any assignment covering less than an entire five percent (5%) Working
Interest shall not serve to increase the number of representatives on
the Operating Committee provided for in the Joint Operating Agreement
and assignor and assignee shall in such cases agree upon a single
representative to represent their combined Working Interests.
6.5 In the event a Surrender covers the entire remaining Badin-II Revised
Area, the Badin-II Revised Licence and all Leases then outstanding,
this Agreement shall be terminated, and the Working Interest Owners
shall after such Surrender have no further obligation under the Act,
the Rules, this Agreement, the Badin-II Revised Licence or any such
Lease except for obligations which have accrued and have not been
discharged prior to such Surrender.
6.6 Notwithstanding the provisions of this Agreement, the term of this
Agreement shall continue, and the obligation of the Working Interest
Owners to Surrender the entirety of the Badin-II
[PAGE # ... 22]
<PAGE> 28
Revised Area or the retained parts of the Badin-II Revised Area shall
be postponed, until the completion or abandonment of any well being
drilled at the end of the third Renewal Period and, in the event such
well results in a Commercial Discovery, thereafter until the
corresponding Lease has expired.
6.7 Upon the termination of this Agreement, the Badin-II Revised Licence
and all Leases then outstanding, each Working Interest Owner shall be
entitled to its share in any unobligated and unexpended funds of the
Working Interest Owners to the extent of such Working Interest Owner's
contribution thereto.
6.8 Subject to Article 6.9 below, the Government shall, in accordance with
the Rules, have the right to terminate this Agreement and revoke the
Badin-II Revised Licence and any Lease upon giving sixty (60) days
written notice of its intention to do so.
6.9 A Lease may be revoked if Commercial Production has not been commenced
within five (5) years from the grant of said Lease; however, it is
understood and agreed that no such revocation shall be made where the
inability to commence production is the result of force majeure, or if
there is construction of transportation system to commence such
Commercial Production.
6.10 The termination of this Agreement for whatever reasons shall be
without prejudice to the obligations incurred and not discharged by
the Working Interest Owners prior to the date of termination.
6.11 In the event of the termination of this Agreement, the Government may
require the Working Interest Owners, for a period not to exceed one
hundred eighty (180) days, to continue, for the account of the
Government, Petroleum production activities until the right to
continue such production has been transferred to another entity. Costs
shall be accounted for pursuant to the terms of the Joint Operating
Agreement.
6.12 Within ninety (90) days after the termination of this Agreement
pursuant to Article 6.8, unless the Government has granted an
extension of this period, the Working Interest Owner shall complete
all reasonable and necessary action as directed by the Government to
avoid environmental damage or hazard to human life or third party
property.
6.13 No consent under the Rules shall be required for (i) the assignment to
another Working Interest Owner of a Working Interest Owner's entire
Working Interest and Petroleum attributable thereto pursuant to the
default and forfeiture provisions of the Joint Operating Agreement,
(ii) the transfer among Working Interest Owners of disproportionate
rights to Petroleum pursuant to the sole risk provisions of the Joint
Operating Agreement, or in order to effect any
[PAGE # ... 23]
<PAGE> 29
reimbursement contemplated by this Agreement or the Joint Operating
Agreement, or (iii) any transfer of a portion of a Working Interest
that occurs by operation of Article IV or the failure or refusal of a
Working Interest Owner to participate with one or more other Working
Interest Owners in an extension or renewal of this Agreement, the
Badin-II Revised Licence or any Lease.
6.14 If Government Holdings assigns all or any portion of its Working
Interest, the assignee shall be liable for its Working Interest share
of any payments required to be paid under Article XX or Article XXII,
after the effective date of the assignment.
[PAGE # ... 24]
<PAGE> 30
ARTICLE - VII
WELLHEAD VALUE
7.1 The Wellhead Value of Crude Oil and Condensate shall be calculated and
applied with respect to each Working Interest Owner for the purposes
of determining royalty as follows:
(a) If the President or his designee elects to acquire Crude Oil
or Condensate to meet national market requirements under the
Rule 41 of the Rules, the Wellhead Value shall be the sales
price actually realised by the Working Interest Owners for a
Barrel of Crude Oil or Condensate, less the actual costs of
gathering, processing, treatment and transportation from the
point of production (wellhead) to the point of sale.
(b) If Crude Oil or Condensate is sold to parties other than
Affiliates in arm's length transactions, the Wellhead Value
shall be the sales price actually realised by the Working
Interest Owners for a Barrel of Crude Oil or Condensate less
the actual cost of gathering, processing, treatment and
transportation from the point of production (wellhead) to the
point of sale.
(c) With respect to all other transactions: (1) to Affiliates, (2)
sales by barter or exchange, and (3) sales other than those
specified in Article 7.1 (a) or (b), the Wellhead Value shall
be greater of:
(i) Actual sales price received less the actual costs of
gathering, processing, treatment and transportation
costs incurred from the point of production
(wellhead) within Pakistan to the point of sale;
(ii) The Wellhead Value per Barrel determined in
accordance with Article 7.1 (a); or
(iii) The Wellhead Value per Barrel determined in
accordance with Article 7.1 (b).
(d) The adjustment on account of transportation and other costs
shall be made on actual cost basis.
7.2 To facilitate computations, the Wellhead Value of Crude Oil and
Condensate shall be determined at the end of each month as the
weighted average value of all such transactions that took place during
the month.
[PAGE # ... 25]
<PAGE> 31
7.3 The Wellhead Value of Natural Gas or other gaseous substances whether
produced from the Area with Crude Oil or Condensate or otherwise shall
be calculated as follows:
(a) If sold to the President or his designee, the Wellhead Value
shall be the price actually received as provided for in
Article-VIII reduced by all compression, dehydration,
liquefaction, treatment and transportation costs incurred from
point of production (wellhead) to the point of sale;
(b) If sold to parties other than Affiliates at the wellhead in
its natural state, the Wellhead Value shall be the price
realised from such sale;
(c) If sold to parties other than Affiliates, not in its natural
state but after processing, the Wellhead Value shall be the
sales price actually realised from such sale less the cost of
processing, gathering, transportation to processing facility,
compression, treatment, dehydration and liquefaction.
(d) If sold to an Affiliate, the Wellhead Value shall be greater
of:
(i) the price actually received reduced by gathering,
compression, dehydration, liquefaction, processing,
treatment and transportation costs incurred from the
point of production (wellhead) to the point of sale;
or
(ii) the Wellhead Value determined in accordance with
Article 7.3(a), (b), or (c) above whichever is
greater.
7.4 The Operator is expressly permitted to use Petroleum produced
hereunder for the drilling, production, pressure maintenance and other
Petroleum Operations free of all costs, royalty and excise duty in
accordance with SRO 545(I)/94 and SRO 546(I)/94 both dated June 9,
1994 provided that the Operator shall not be entitled to include any
notional cost of Petroleum so used in claiming its business expenses
for income tax purposes.
7.5 To facilitate computations, the Wellhead Value of Natural Gas shall be
determined at the end of each month as the weighted average value of
all such transactions that took place during the month.
7.6 Each of the Private Working Interest Owners shall deliver to the
Government at the time that the audit report required under Article
19.1 is delivered, a certificate prepared by their respective
chartered accountants that certifies that for its Working Interest for
the Year for which the certificate relates that (i) its royalty
obligation has been determined by reference to the Wellhead Value, and
[PAGE # ... 26]
<PAGE> 32
(ii) processing charges with respect to its share of the Royalty
Petroleum to the extent that reimbursement has been received from the
Government, have been deducted from its operating expenses or included
as "other income" for tax purposes, and (iii) the amounts referred to
in clauses (i) and (ii) have been reflected in its audited accounts.
[PAGE # ... 27]
<PAGE> 33
ARTICLE - VIII
NATURAL GAS
8.1 Upon a Commercial Discovery and within three (3) months of the Working
Interest Owners making a written request indicating the recoverable
reserves, daily supply volume, quality, pressures as well as other
relevant information, the President will have the option to decide to
purchase the Natural Gas by making the necessary allocation to a
specified buyer. Thereafter, the Working Interest Owners and the
buyer(s) within six (6) months thereof shall mutually agree upon the
time frame for the construction of pipeline network and other terms
and conditions including, but not limited to, "take or pay" basis for
utilization of such gas. If the indication of a specified buyer is not
given by the President within a period of three (3) months as referred
to above or the agreement is not reached with the specified buyer
within six (6) months, the Working Interest Owners shall be free to
use Natural Gas for power generation, fertilizer production or any
other industrial or commercial purpose.
8.2 Whenever a Working Interest Owner is selling pipeline quality Natural
Gas of acceptable specification to the President or his designee, it
shall subject to Article 9.3, receive a price per Million BTUs
("MMBTU"). The price to be paid shall be determined for a six (6)
monthly period (hereinafter referred to as "the Price Notification
Period") starting at eight o'clock (8:00) a.m. P.S.T. on 1st January
and 1st July each year except the first period which may commence from
the Date of Commercial Production and continue until the 30th of June
or 31st of December as the case may be. The price to be notified per
MMBTU shall be computed as follows:
(1) First determine the "Marker Price" which shall be sixty-seven
and five tenths percent (67.5%) of the weighted average C&F
price per barrel of the basket of Crude Oils imported into
Pakistan during the first six (6) months period of the seven
(7) months period immediately preceding the relevant Price
Notification Period.
(2) Using the appropriate conversion factor, convert the Marker
Price to MMBTU rounding the quotient to four (4) decimal
places to arrive at the Marker Price per MMBTU.
(3) Not later than twenty (20) days prior to the commencement of
the Price Notification Period during which the Operator
expects first gas production to commence, Operator shall
submit to the authority
[PAGE # ... 28]
<PAGE> 34
established under the Natural Gas (Price for Supplies by
Producers) Rules, 1976 (hereinafter referred to as the "Price
Determining Authority") a calculation of Marker Price in US
Dollars to be fixed on the first, day of such Notification
Period.
(4) Thereafter, Operator shall submit to the Price Determining
Authority the relevant Marker Price calculation in US Dollars
(applicable to each six (6) month Price Notification Period)
prior to each preceding 10 December and 10 June, respectively.
(5) The President shall ensure that details of the quantities and
C&F prices of the Crude Oils imported into Pakistan as
referred to in Article 8.2(1) hereof, are supplied to Operator
not later than twenty- five (25) days prior to the
commencement of the relevant Price Notification Period in
order that they may be included in the calculations to be made
pursuant to Article 8.2(1) and (2).
(6) Operator shall submit to the Price Determining Authority a
draft pricing notification setting out the US Dollar prices
resulting from Article 8.2(1) and (2) above for the relevant
Price Notification Period at the same time as submitting the
calculation pursuant to Article 8.2(3) and (4) above (as the
case may be).
(7) Such pricing notification shall be published in US Dollars in
the official Gazette for the purposes of the Gas Sales
Agreement within forty five (45) days of the date of receipt
of the aforesaid draft pricing notification.
8.3 For purchases of Condensate and LPG to meet internal requirements of
Pakistan, the price payable to Working Interest Owners, subject to
Article 9.3, shall be calculated as under:
(a) The price in US Dollars per Barrel allowed for Condensate,
delivered at the nearest operating refinery shall be equal to
the FOB price of internationally quoted comparable condensate
as mutually agreed by the parties. No other adjustment or
discount will apply.
(b) The price allowed for LPG produced from new projects shall be
equal to the C&F price in US Dollars calculated by using the
FOB price as reported in a mutually acceptable publication and
the freight cost based on proper off-loading facilities at
Karachi as may be notified by the Government from time to
time.
[PAGE # ... 29]
<PAGE> 35
ARTICLE - IX
RIGHT OF ACQUISITION OF PETROLEUM
9.1 Should the President require the Working Interest Owners (other than
Government Holdings) to deliver Petroleum to meet the domestic
requirements of Pakistan according to Rule 41 of the Rules, the
following shall apply:
(i) If in any year there is domestic demand in excess of the
Government's and OGDC's share of production, the President may
require such Working Interest Owners to sell Crude Oil in
Pakistan on a pro-rata basis with other producers in Pakistan,
according to the Crude Oil production of each producer in a
Calendar Year. The President shall give the foreign Working
Interest Owners at least three (3) months notice in advance of
such requirements, and the term of the supply will be on an
annual basis. The pro-rata basis shall be calculated by
multiplying the excess of domestic consumption over the amount
of Crude Oil available to the President and OGDC from the
total Crude Oil production in Pakistan, by a fraction, the
numerator of which is the Working Interest share of production
of such Working Interest Owner less Royalty Petroleum, and the
denominator of which is the total production in Pakistan less
the amount of Crude Oil available to the President and OGDC,
provided that a Working Interest Owner will have available for
export (or such other disposition as it may decide upon) in
any one year not less than sixty percent (60%) of its Working
Interest share of production.
(ii) Whenever a Working Interest Owner, other than Government
Holdings, is selling Crude Oil to the President or his
designees such Working Interest Owner shall be entitled to
receive a price in US Dollars per barrel, subject to Article
9.3 for such Crude Oil delivered at the cost of the Working
Interest Owners to the nearest operating refinery which shall
be calculated as under:
(a) (1) The arithmetic average of the FOB spot prices
during the month of delivery of a basket of
Arabian/Persian Gulf Crude Oils or a Crude
Oil comparable in quality to Crude Oil
produced under this Agreement as mutually
agreed; or
(2) In the event no agreement is reached as to
the basket or a comparable Crude Oil or on
related matters, then the basis shall be FOB
market price of a Crude Oil as may be
mutually agreed which can be demonstrated to
be
[PAGE # ... 30]
<PAGE> 36
applicable to contracts negotiated with
unrelated parties on an arms length basis
under which the consideration is wholly cash,
payable on normal terms.
(b) Plus freight for marine transportation of Crude Oil
from Ras Tanura, Saudi Arabia to Karachi, Pakistan as
applicable from time to time for chartered vessels.
(c) Plus or minus a quality yield differential between
Crude Oil produced under this Agreement and the Crude
Oil referred to in Article 9.1 (ii) (a) above. For
this purpose the differential shall be determined on
yield value based on refinery operating conditions
where the Crude Oil will be processed and at mutually
agreeable reference prices of petroleum products
prevailing in Arabian/Persian Gulf and published in
an internationally recognized publication acceptable
to the Parties.
9.2 The President or his designee shall purchase Crude Oil and Condensate
delivered at "nearest operating refinery" Natural Gas at the wellhead,
"transmission system" or the "main consumption centre" and LPG at "a
point" as may be agreed. Title to and risk of loss of the Petroleum
purchased by the President or his designee shall pass at the transfer
points referred to above which shall be construed as the "Delivery
Points" for the purpose of this Agreement.
9.3 The President or his designee shall pay to a Pakistani Working
Interest Owner up to thirty percent (30%) of its sales proceeds in
foreign exchange for all Petroleum purchases in accordance with the
provisions of this Article IX, the Petroleum Policy and the rate of
exchange prevailing on the date of transaction except as specifically
provided herein. Payments for any Petroleum purchased from foreign
Working Interest Owners by the President or his designee shall be by
remittance in United States Dollars to a bank designated by the
foreign Working Interest Owners of an amount equivalent to the
invoiced price of Petroleum purchased during the month within thirty
(30) days of receipt of invoice. If not so paid, the liquidated
damages shall be paid on the unpaid balance after the due date at the
rate per annum of 1.5 percentage points above the London interbank
offer rate ("LIBOR") for one month deposits of U.S. Dollars as
reported by an agreed publication.
9.4 The President shall have the right to purchase all or a portion of any
Working Interest Owners' share of Petroleum in case of a national
emergency or war at the price determined in accordance with Article
9.1.
[PAGE # ... 31]
<PAGE> 37
ARTICLE - X
DISPOSAL OF PETROLEUM
10.1 Each Working Interest Owner shall have the right to take in kind and
separately dispose of its share of Petroleum produced and saved in
accordance with this Agreement, the Licence or any Lease at
competitive prices on arm's length basis under which the consideration
is wholly cash payable on normal terms. Subject to Article IX and the
Rules, each Working Interest Owner shall have the right to export from
Pakistan, free from any export restriction, duty or similar tax its
share of Petroleum, including Petroleum delivered to it in accordance
with the provisions of the Joint Operating Agreement, or to otherwise
dispose of such Petroleum. The President shall issue or cause to be
issued any permits or authorizations required for such exports within
a reasonable time and no export duties or other fees shall be levied
or charged.
If requested by the President at any time or from time to time,
Private Working Interest Owners shall use their good offices to assist
OGDC and Government Holdings in disposing of shares of Petroleum
produced hereunder at the best available prices; provided that in no
event shall Private Working Interest Owners be required to purchase or
otherwise provide a market for OGDC and/or Government Holdings' share
of Petroleum produced hereunder. The OGDC and Government Holdings
shall reimburse the Private Working Interest Owners for all expenses
incurred in rendering to the OGDC and Government Holdings any such
assistance on a no-profit no-loss basis.
10.2 The Working Interest Owners shall refrain from exporting Petroleum
from Pakistan to countries prohibited by the Pakistani laws,
regulations and administrative requirements.
10.3 Natural Gas which is not used in Joint Operations, and the processing
and utilization of which, in the opinion of the Working Interest
Owners, is not economical, shall be returned to the subsurface
structure if economical to do so, or may be flared with the approval
of the Government in accordance with the Rules. In the event the
Working Interest Owners choose not to process and sell Natural Gas,
the President may elect to off-take at the outlet flange of the
gas-oil separator and use, either itself or through its designee, such
Natural Gas if it is not required for Joint Operations. There shall be
no charge to the President or his designee for such Natural Gas.
[PAGE # ... 32]
<PAGE> 38
ARTICLE - XI
FOREIGN EXCHANGE
11.1 The Operator may call for contributions to the Joint Account (as
defined in the Joint Operating Agreement) to be made in such currency
components (i.e., Rupees or US Dollars and other freely convertible
foreign exchanges) as the Operator may from time to time specify,
giving due consideration to the currency aspects of Expenditures
anticipated to be made under this Agreement. Each Working Interest
Owner shall contribute its Badin-II Revised Working Interest share of
each currency component.
11.2 The Operator shall be allowed to keep the foreign exchange
contributions of the Working Interest Owners, as may be required for
incurring Expenditures in foreign exchange, in a foreign currency bank
account in a scheduled bank in Pakistan, and shall be free to utilize
the amount thereof for incurring foreign exchange Expenditures under
the Joint Operating Agreement, subject to appropriate documentation of
the amounts utilized.
11.3 If any Private Working Interest Owner assigns an interest to a
non-Pakistani assignee pursuant to Article VI, such Private Working
Interest Owner shall be allowed to retain abroad and freely dispose of
all proceeds resulting from such assignment.
11.4 The Private Working Interest Owners shall be entitled (a) to receive
in US Dollars or in Pakistani Rupees payment for their share of
Petroleum exported or sold under this Agreement and (b) to retain
abroad and freely dispose of such payments in accordance with the
relevant foreign exchange rules as in effect on the Effective Date.
11.5 The Working Interest Owners may meet any Rupee obligation which may be
discharged within Pakistan (including without limitation obligations
to contribute Rupees to the Joint Account for each of the Badin-II
Revised Area and obligations to pay taxes and other sums to agencies
of the Government) with Rupees obtained pursuant to this Agreement.
The President undertakes that the State Bank of Pakistan will make
available for sale to the Private Working Interest Owners, as
requested, Rupees in sufficient amounts to meet the Private Working
Interest Owner needs on surrender of an equivalent amount in US
Dollars or other convertible currency.
11.6 The Working Interest Owners shall effect all purchases and sales of
Rupees contemplated in this Agreement (including without limitation
the purchase of
[PAGE # ... 33]
<PAGE> 39
Rupees for contribution to the Joint Account for the Badin-II Revised
Area as provided in Article 11.1, the sale of Rupees and the purchase
of Rupees to meet local obligations as provided in Article 11.5) at
the official rate of exchange established by the Foreign Exchange Rate
Committee on the day of the relevant purchase or sale of Rupees. The
President undertakes that such rate of exchange shall never be such as
to constitute a discrimination against any Private Working Interest
Owner in particular or the Petroleum industry in general.
11.7 The Private Working Interest Owners shall pay cash royalties in the
currencies for which the corresponding production was sold.
11.8 The Private Working Interest Owners shall remit funds to Pakistan
through normal banking channels sufficient to meet all Pakistan Rupee
obligations under this Agreement to the extent Rupees are not
available in Pakistan.
11.9 The Private Working Interest Owners shall not avail themselves of any
Rupee borrowing facilities.
[PAGE # ... 34]
<PAGE> 40
ARTICLE - XII
IMPORTS AND EXPORTS
12.1 (a) The Operator, its contractors and subcontractors engaged in
Petroleum Operations under this Agreement shall be permitted
to import, export, transfer and dispose of the machinery,
equipments, materials, specialised vehicles, accessories,
spares, chemicals and consumables, etc. in accordance with SRO
367(1)/94 dated 9th May, 1994 (Annexure IV - Exhibit A) as
amended from time to time, provisions of CGO-2/93 dated 20th
May, 1993 wherever applicable (Annexure IV - Exhibit B), and
the provisions of this Agreement. No license or
import-cum-export authorization fee shall be levied on such
imports/exports in accordance with Import Fee Order 1993 as
amended by SRO 336(1)/94 dated 26th April, 1994 (Annexure IV -
Exhibit C).
(b) The initial list of machinery, equipment, materials,
specialised vehicles, accessories, spares, chemicals and
consumables, etc. required for Petroleum Operations approved
by the relevant Regulatory Authority under Article 12.1(a)
above is attached as Annexure IV - Exhibit D hereto. The
Operator shall, however, as provided in Rule 60 of the Rules,
give preference to goods which are produced or available in
Pakistan and services which are rendered by Pakistani
nationals and companies provided such goods and services are
offered on competitive terms. National firms which appear
capable of supplying goods and services to the type demanded
shall always be included in invitations to bid. For
classification of items imported by a Petroleum Sector
Company, its contractors or subcontractors, the harmonized
system of classification will be followed. The local
manufacturers and producers of the Petroleum Sector machinery
and equipment etc. will be entitled to concessions contained
in SRO 366(1)/94 dated 9th May, 1994 (Annexure IV - Exhibit E)
and SRO 798(I)/90 dated July 30, 1990.
(c) Foreign employees and consultants of the Operator and its
contractors and subcontractors will be entitled to
import/export of used and bonafide personal and household
effects, excluding passenger vehicles, in accordance with
instructions contained in Central Board of Revenue's letter C.
No. 10(14)/93-ICM&CON dated 13th June, 1994 (Annexure IV -
Exhibit F).
[PAGE # ... 35]
<PAGE> 41
12.2 The Operator, its contractors or their subcontractors shall be
entitled to export such of their items as have been imported into
Pakistan and are not required for the Petroleum Operations without
restriction and without the payment of any fee, tax or export duty.
The Operator shall ensure that equipments/materials imported by
itself, its contractors or subcontractors under this Article XII
against its import-cum-export authorization are exported if all the
Joint Operations under this Agreement are terminated unless otherwise
permitted in accordance with this Agreement.
12.3 Import of the items permitted under this Article XII hereof shall be
allowed subject to the following conditions:
(a) A condition shall be stamped on the import authorizations that
the item shall not be sold in Pakistan except with prior
permission of the Government.
The permission required under this Article 12.3(a) shall not
be necessary with respect to the transfer of title to any
property made pursuant to or incidental to any assignment by
the Working Interest Owners of all or any part of their
Working Interest under the provisions of Article I of this
Agreement.
(b) The Operator shall maintain proper accounts, statements and
records of all consumable stores received and expended and
send copies thereof (in duplicate) to the Ministry of Commerce
concerned by the 30th of January each year and finally within
thirty (30) days of the closing of operations in Pakistan.
(c) (i) Commissary stores can be imported after the first
arrival of an expatriate employee of the Operator
(Petroleum Sector Exploration and Production
Company), its contractors and their subcontractors in
accordance with instructions contained in the Central
Board of Revenue's letter C.No. 10(14)/93-ICM&CON
dated 13th June, 1994 (Annexure IV - Exhibit F). Such
imports shall be confined to the items shown in
Annexure IV - Exhibit G excepting such items as are
locally available of proper standard. Such items
shall be specified by the Ministry of Commerce once
each year in the month of January.
(ii) As soon as an expatriate employee arrives in
Pakistan, an application will be made for the grant
of an import permit for the commissary stores
required for his indicating the duration of his
programmed stay in Pakistan.
[PAGE # ... 36]
<PAGE> 42
(iii) Accounts for the sale of tobacco and liquor (if
imported) and drugs will be maintained for each
individual while those of the other items will be
maintained on an over-all basis.
(iv) Items of food and other commissary goods will be
stamped clearly to avoid resale in the market.
(v) CBR booklets will be maintained by individuals.
(d) Any other items of personal use, e.g. arms and ammunition,
pets etc., will not be permitted unless the conditions for
their import such as arms licences from district authorities,
quarantine requirements, etc. are fulfilled.
12.4 Subject to the rights granted under the provisions of this Agreement
and particularly those granted under this Article XII, any items
banned for import into Pakistan under the Import Policy in force from
time to time shall not be permitted without specific permission to be
obtained before shipment of goods from abroad.
12.5 The Operator and its contractors and subcontractors shall not be
liable to pay any tax, assessment, levy, octroi or charge imposed or
levied on the transportation or movement of the scheduled machinery
and equipment to and from the Badin-II Revised Area or on any item
imported/exported under this Article XII.
12.6 Imports/Exports under this Article shall be affected in accordance
with the Import/Export Policy in force on the Effective Date.
12.7 At least ten percent (10%) of the value of computer software contracts
shall be utilized by the Operator for using local software
capabilities, subject to such software capabilities being available in
Pakistan at a competitive price.
12.8 Operator, its contractors and subcontractors, shall be entitled at any
time to export any item or items for replacement, repair, modification
or renovation, and may re-import the same without the payment of
additional import duties subject to the production of a certificate
from the Director General Petroleum Concessions that the item needs to
be exempted for the said purpose.
[PAGE # ... 37]
<PAGE> 43
ARTICLE - XIII
TAXATION
13.1 The profits or gains of each of the Working Interest Owners derived
from the operations hereunder and the determination of the tax thereon
shall be computed for purposes of Income Tax in accordance with the
provisions of the Income Tax Ordinance, 1979 (No. XXXI of 1979)
hereinafter referred to as the "Ordinance" and the rules contained in
Part I of the Fifth Schedule to the Ordinance, (hereinafter referred
to as the "Fifth Schedule") as in force on the Effective Date.
13.2 Where any Expenditures allocable to a Surrendered area or to a
drilling of a dry hole are deemed to be lost under Rule 2(2) of said
Schedule to the Ordinance, such Expenditures shall be allowed to the
Private Working Interest Owners as provided in Rule 2(3) (a) of the
Fifth Schedule in accordance with the amount actually spent by the
respective Working Interest Owner at the time such Expenditure was
incurred in the Badin-II Revised Area; provided, however, that, in
accordance with Clause (3) of the Fifth Schedule, all Expenditures
deemed to have been lost in terms of Rule 2(2) of the same Schedule
shall be allowed to be set off against all other income of the Working
Interest Owner (other than dividend income) accruing or arising from
or under any separate business or undertaking or this Agreement or
from any other past, present or future agreement entered into by the
Working Interest Owners with the President or the Government for
Petroleum exploration and development or from any other activity, on a
fully consolidated basis in accordance with Rule 2(3) of the Fifth
Schedule. Each Private Working Interest Owner hereby elects Subrule
2(3)(a) of the Fifth Schedule. OGDC hereby elects Subrule 2(3)(b) of
the Fifth Schedule.
13.3 In accordance with the provisions of Rule 4 of the Fifth Schedule,
read with the Act, the sum of payments by each of the Working Interest
Owners to the Government and taxes on income shall be limited to
fifty-five percent (55%) of profits or gains derived from the
operations or part of the operations. Provided that the aggregate of
the taxes on income and other payments to the Government shall not be
less than fifty percent of the profits or gains derived from the said
operations before the deduction of the payments to Government but
after making the depletion allowance for determining such profits and
gains as allowed under Rule 3 in Part I of the Fifth Schedule.
[PAGE # ... 38]
<PAGE> 44
13.4 In accordance with Clause (2) of the Fifth Schedule, royalty shall be
payable by the Working Interest Owners at the rate of twelve and
one-half percent (12-1/2%) of the Wellhead Value of any Petroleum
produced and saved by the Working Interest Owners and, for the
purposes of Article 13.3 hereof, shall form part of the sum of
payments to the Government.
13.5 Depreciation shall be allowed to the Working Interest Owners in
accordance with the provisions of the Ordinance and in particular the
Third Schedule thereof.
13.6 In case of any conflict in respect of taxation matters between any of
the provisions of this Agreement including its Annexes, and the
provisions now in effect of the Ordinance, and the Fifth Schedule
thereof, read with the Regulations as amended and in force on the
Effective Date, the provisions of the latter shall prevail.
[PAGE # ... 39]
<PAGE> 45
ARTICLE - XIV
FORCE MAJEURE
14.1 Performance under and pursuant to this Agreement, the Badin-II Revised
Licence and any Lease by any Working Interest Owner (including the
Operator) shall be excused in the event such performance is prevented
by act of God, by law, war, strikes, lockouts, fires, floods,
tornadoes, cyclones, typhoons, lightning, explosions, acts of public
enemy, riot, insurrection or civil disturbance, acts or omissions to
act of authorities, or other happenings beyond the reasonable control
of any Working Interest Owner (including the Operator) and will not be
deemed to be a breach of this Agreement; provided, however, the
Working Interest Owner will be required to use reasonable diligence in
overcoming the obstacle, and the performance will be resumed within a
reasonable time or such time as may be agreed by the parties hereto
after the obstacle has been removed.
14.2 The term of this Agreement and of the Badin-II Revised Licence, a
Lease or the period provided in this Agreement for the performance by
any Working Interest Owner of any obligation, the performance of which
was prevented or delayed by an event of force majeure as the case may
be, shall be extended for a period equal to the duration of the force
majeure situation and such further period as is reasonably required to
resume operations.
14.3 In the event force majeure exceeds a period of three (3) continuous
years during the term of the Badin-II Revised Licence, the Operating
Committee or the Government may terminate the Badin-II Revised Licence
or this Agreement as it relates to the Licence on three (3) months
written notice and shall thereby be relieved of all outstanding work
obligations and training and social welfare obligations that have not
yet accrued under or with respect to the Badin-II Revised Licence. In
the event that the Badin-II Revised Licence is terminated pursuant to
this Article 14.3, the Working Interest Owners shall have the right to
be regranted the Badin-II Revised Licence for the remaining period of
its term within six (6) months after being notified in writing by the
Government that the conditions giving rise to the event of force
majeure no longer exist.
[PAGE # ... 40]
<PAGE> 46
ARTICLE - XV
MANAGEMENT AND OPERATIONS
15.1 Union Texas, as Operator, shall prepare an annual work programme and
budget for the Badin-II Revised Area for each Calendar Year during the
term of this Agreement. Each such proposed work programme and budget
shall set out in reasonable detail the work to be carried out,
facilities to be purchased or created, training and employment
programmes, Expenditures on establishment, salaries and wages, social
welfare schemes to be undertaken, and an estimate of the Expenditures
to be incurred.
15.2 Such annual work programmes and budgets shall be prepared and
submitted to the Working Interest Owners at least sixty (60) days
prior to the first day of the Calendar Year covered thereby.
15.3 All matters concerning Joint Operations conducted with respect to the
Badin-II Revised Area required to be submitted for the approval by the
Operating Committee pursuant to the Joint Operating Agreement shall be
submitted for approval to an Operating Committee composed of at least
one representative of each Working Interest Owner. The President shall
nominate the Chairman of the Operating Committee who shall have no
vote. The representative of each Working Interest Owner shall have a
vote equal to the Badin-II Revised Voting Interest of such party. All
decisions or determinations of the Operating Committee shall require a
vote equal to fifty-five percent (55%) of the Badin-II Revised Voting
Interests (determined at the time and with respect to the subject
matter of the decision or determination before the Operating
Committee) of the Working Interest Owners, except as otherwise
provided in Article 5.2 and Article 8 of the Joint Operating
Agreement.
15.4 The Operator shall conduct all exploration, exploitation, drilling,
development and production operations in accordance with this
Agreement and the Rules. In case the Rules or this Agreement do not
provide for a specific operation, then customary good oil field
practice will be followed. The Operator shall set up an organization
in Pakistan with sufficient competence and capacity to conduct and
perform the Joint Operations in accordance with the provisions of the
Rules and this Agreement.
15.5 The Working Interest Owners shall on Surrender of the entire Badin-II
Revised Area or part thereof during the term of this Agreement deliver
to the President all data in original form including but not limited
to geological, geophysical surveys and drilling operations together
with interpretation, shotpoints, vibrated
[PAGE # ... 41]
<PAGE> 47
points, magnetic tapes and other data, plans and charts thereof
relevant to the area Surrendered. On receipt of the above, the
President shall enjoy sole proprietary rights thereto, provided that
each Working Interest Owner may retain a copy thereof for use in
evaluating any retained part of the Badin-II Revised Area. All such
data retained by the Working Interest Owners delivered to the
President shall continue to be subject to the obligations of
confidentiality as set forth in Article 11 of the Joint Operating
Agreement.
15.6 The Operator shall as far as is reasonably practicable correctly label
and preserve for a period of twelve (12) months for reference
characteristic samples of strata or water encountered in any bore-hole
or well and samples of any Petroleum discovered in the Badin-II
Revised Area. The characteristic samples of said strata shall include,
but shall not be limited to, cuts of all cores and cuts of all ditch
samples. All characteristic samples, including ditch and core samples,
shall be supplied by the Operator to the President automatically
without any request being made by the President.
15.7 Any person or persons authorized by the Director General Petroleum
Concessions shall be entitled, at the cost of the Working Interest
Owners, to be present at their sole risk during any or all of the
Joint Operations, provided, that such persons abide by the applicable
safety rules. The Director General Petroleum Concessions shall give to
the Operator reasonable notice of such authorizations.
15.8 The Operator may utilize for the purpose of Joint Operations, drilling
and other equipment owned by OGDC or any of the Working Interest
Owners (or their respective Affiliates) as may be available from time
to time, provided that such equipment, in the opinion of the Operator,
in consultation with the Operating Committee, is suitable and adequate
for the efficient and expeditious performance of the Joint Operations
and that the cost, quality, and other conditions for the use of the
same are competitive with those applicable to comparable equipment
then available from any other source.
15.9 Subject to approval in accordance with Rule 34 of the Rules, the
Working Interest Owners have the right to lift and transport Petroleum
from each of the Badin-II Revised Area, either through transportation
facilities owned wholly or partly by them or through access
transportation facilities owned by a third party.
The Working Interest Owners and their respective Affiliates and third
party customers shall have the right and liberty to transport
Petroleum produced from the Badin-II Revised Area in such tankers as
they may see fit; provided, that in the event a Working Interest Owner
or its Affiliates wishes to charter any tanker at any time to
transport any such Petroleum as they may own or have
[PAGE # ... 42]
<PAGE> 48
acquired and the President or any other Pakistani owner then having
available a Pakistani flag tanker which appears to the Working
Interest Owner or its Affiliates to be acceptable after consideration
of the age and state of condition and repair of the tanker and
suitable in all other respects for that purpose, the Working Interest
Owner or its Affiliate shall give preference to chartering such
tanker; provided that the duration, rates and conditions of any such
charter shall be agreed between the parties and the said rates and
conditions shall be competitive with those prevailing in the
international market.
15.10 (a) Each Working Interest Owner and the Operator shall undertake
to abide and comply with the instructions issued by the
Government from time to time in relation to the matters set
out below:
(i) the foreign nationals employed by the Operator before
arriving in Pakistan shall possess complete and
authorized travel documents for their stay in
Pakistan. In case they wish to extend their stay in
Pakistan beyond the specified period, they shall
obtain prior permission from the appropriate
authorities;
(ii) the employees of the Operator shall refrain from
taking photographs of prohibited and restricted
sites;
(iii) the employees of the Operator shall not visit areas
within ten (10) miles of the international border;
(iv) the programme of visits and movements of field survey
parties shall be forwarded to appropriate
authorities, local administration and the Director
General Petroleum Concessions well in advance;
(v) in the case of intended visits to the Badin-II
Revised Area, the Operator shall furnish the names,
nationalities and passport numbers (with places of
issue and validity periods) of foreign nationals
employed by the Operator and its contractors and
sub-contractors well in advance to the appropriate
authorities, local administration and the Director
General Petroleum Concessions; and;
(vi) foreign nationals shall be employed with the
requisite work permit and approval from the
Government.
(b) The Operator will use all reasonable endeavours to include in
any contract for the Joint Operations with any contractor or
subcontractor a provision requiring the employees of such
contractors or sub-
[PAGE # ... 43]
<PAGE> 49
contractors to abide and comply with the instructions referred
to in this Article 15.10.
15.11 If and insofar as the Operator may at any time require the use of
helicopters for the purpose of its operations under this Agreement and
any agency in Pakistan may then have any helicopters available which
appear to the Operator to be in all respects suitable for such
purpose, the Operator shall hire such helicopters as it may then
require from the said agency; provided always, that the terms and
conditions for such hiring shall be and remain competitive with those
applicable to helicopters of comparable capability then available from
any other source.
15.12 The President shall supply to the Operator at an agreed cost, copies
of any and all geological, geophysical, well and other data in the
public domain which it has in its possession pertaining to the
Badin-II Revised Area or any free adjoining acreage. Such data shall
be retained in strict confidence by the Operator and shall not be
disclosed to any third party (except to its employees consultants, or
Affiliates who shall be similarly bound to treat it strictly
confidential).
15.13 (a) The Operator shall furnish to the Director General Petroleum
Concessions all reports required in accordance with the Rules.
The records and said reports shall be retained in strict
confidence by the Director General Petroleum Concessions and
shall not be disclosed to any third party (except to
Government employees or consultants who shall be similarly
bound to treat them as strictly confidential) until the
Surrender of that part the Badin-II Revised Area to which such
records and reports relate; except as provided for in the
Rules.
(b) The Operator shall submit to the Director General Petroleum
Concessions a copy of all plans information, occasional
reports including such reports prepared inside and/or outside
Pakistan prepared by itself or others relating the Badin-II
Revised Area and to all geological, geophysical and drilling
operations thereof including but not limited to copies of
primary data (field and reservoir data), transparencies of
seismic sections, interpretations, graphs, charts and well
logs as provided in the Rules.
(c) The Operator shall furnish to the Director General Petroleum
Concessions such other plans and information as to the Joint
Operations in the Badin-II Revised Area as the Director
General Petroleum Concessions may from time to time require.
[PAGE # ... 44]
<PAGE> 50
(d) The Operator shall on Surrender of the entire Badin-II Revised
Area or part thereof, during the term of this Agreement,
deliver to the President all data in original including but
not limited to geological, geophysical surveys and drilling
operations together with interpretations, shot-points,
vibrated points, magnetic tapes, transparencies of seismic
sections etc. plans and charts thereof. On receipt of the
above, the President shall enjoy sole proprietary rights
thereto.
(e) The Working Interest Owners shall maintain the confidentiality
of the data required during the term of the Badin-II Revised
Licence or any Lease in accordance with the provisions of this
Agreement after the termination of this Agreement; provided,
however, that the Working Interest Owners may disclose any
such information to a third party if such third party enters
into an appropriate confidentiality agreement.
15.14 Unless otherwise agreed to by the Government, in case of export of any
rock or Petroleum samples from Pakistan for the purpose of testing and
analysis, samples equivalent in size and quantity shall, before such
exportation, be delivered to the Government.
[PAGE # ... 45]
<PAGE> 51
ARTICLE - XVI
ARBITRATION
16.1 Any question or dispute between one or more Private Working Interest
Owners, as one party, and the President, as the other party, arising
out of or in connection with the terms of this Agreement or the
Badin-II Revised Licence or any Lease granted pursuant to this
Agreement (regardless of the nature of the question or dispute) shall,
as far as possible, be settled amicably. Failing an amicable
settlement within a reasonable period (which in no event shall exceed
three (3) months after any party to such dispute gives to the other
party notice of its intention to submit such question or dispute to
arbitration) such question or dispute shall at the request of any such
party be submitted to the International Centre for Settlement of
Investment Disputes (hereinafter called the "Centre") established by
the "Convention on the Settlement of Investment Disputes Between
States and Nationals of Other States" and the President and Union
Texas, Occidental, OGDC and Government Holdings to the extent required
by said Convention, hereby consent to arbitration thereunder. The
venue of the arbitration shall be as mutually agreed between the
parties to such dispute, in Pakistan or elsewhere. If such mutual
agreement cannot be reached, the venue shall be decided by the Centre.
The award rendered shall be final and conclusive. The judgment on the
award rendered may be entered in any court having jurisdiction or
application may be made in such court for a judicial acceptance of the
award and an order of enforcement as the case may be.
16.2 If, for any reason, the request for arbitration proceedings is not
registered by the Centre, or if the Centre fails or refuses to take
jurisdiction over such dispute or the President is not a party to the
dispute, such dispute shall finally be settled by arbitration at The
Hague under the Rules of Arbitration of the International Chamber of
Commerce (the "Chamber Rules") and by three (3) arbitrators appointed
in accordance with the Chamber Rules. No such arbitrator shall be a
national of Pakistan or of the United States of America or the
nationality of any other party to the dispute nor shall any such
arbitrator be an employee or agent or former employee or agent of any
party to the dispute. The award rendered shall be final and
conclusive. The Judgment on the award rendered may be entered in any
court having jurisdiction or application may be made in such court for
judicial acceptance of the award and an order of enforcement as the
case may be.
16.3 This Article XVI shall apply only in a case of a dispute between the
Working Interest Owners or between the Working Interest Owners and the
President. In
[PAGE # ... 46]
<PAGE> 52
the event of a dispute between the Pakistani Working Interest Owners
or a dispute between the Pakistani Working Interest Owners and the
President the arbitration shall be conducted in accordance with the
Arbitration Act, 1940.
[PAGE # ... 47]
<PAGE> 53
ARTICLE - XVII
REFINERY
17.1 No Private Working Interest Owner shall be required to erect a
refinery, notwithstanding any provisions of the Rules.
17.2 The Private Working Interest Owners renounce any claim to participate,
on grounds of the production of Crude Oil in Pakistan, in any refinery
which may be erected by the President.
[PAGE # ... 48]
<PAGE> 54
ARTICLE - XVIII
OTHER MINERALS
18.1 When any mineral, other than Petroleum and minerals necessary for the
generation of nuclear energy, is discovered by the Working Interest
Owners and the President does not have a pre-existing policy for
development and exploitation of such mineral by a non-Pakistani
corporation, a Working Interest Owner shall have the right to elect
within six (6) months after the date on which Operator notifies the
Director General Petroleum Concessions of such discovery, to develop
and exploit such mineral subject to reaching an accord after such
election with the appropriate licensing authority as to the terms and
conditions of an agreement governing the development and exploitation
of such mineral. The minerals necessary for the generation of nuclear
energy include, among others:
1.Uranium
2.Thorium
3.Zirconium
4.Niobium
5.Hafnium
6.Lithium and
7.Vanadium
18.2 Discovery of all minerals necessary for the generation of nuclear
energy shall be reported by Operator to the Pakistan Atomic Energy
Commission and the Director General Petroleum Concessions. The Working
Interest Owners shall have no right to develop and exploit such
minerals unless specific approval/concurrence is given by Pakistan
Atomic Energy Commission for the development and exploitation of these
nuclear minerals.
18.3 Minerals, other than those necessary for the generation of nuclear
energy, produced in suspension or combination with Petroleum shall
belong to the Working Interest Owners, subject to payment of royalty
if marketed. Royalty shall be at the rate specified by the appropriate
authority.
18.4 The income derived from the minerals, other than those necessary for
the generation of nuclear energy, produced in suspension or
combination with Petroleum shall be governed by Part II of the Fifth
Schedule of the Income Tax Ordinance 1979 (NO.XXXI of 1979) as amended
from time to time.
[PAGE # ... 49]
<PAGE> 55
ARTICLE - XIX
AUDIT
19.1 The Operator shall maintain correct records and accounts of all
Expenditures made for Joint Operations, of all production obtained
from the Badin-II Revised Area and of all property acquired for the
Joint Account in accordance with customary industry practices and the
Accounting Procedure. The accounts shall be audited for the period
from the Effective Date to the end of the Calendar Year, and
thereafter annually by an independent firm of Chartered Accountants
selected by the Operator and approved by the Operating Committee.
Copies of the audit reports shall be delivered to the President and to
each of the Working Interest Owners within six (6) months of the end
of each Calendar Year. If neither the President nor the Working
Interest Owners or any of them shall take exception to any such
audited accounts within twenty-four (24) months after its receipt of
copies of the report relating thereto, the same shall be final and
binding on the Working Interest Owners and the President; provided,
however, that the accounts and support vouchers and documents,
together with such reasonable facilities as may be required for the
audit of the Joint Operations, shall be made available to the Auditor
General of Pakistan (with notification to the Director General,
Petroleum Concessions that this has been done) who may take such
action as he deems fit within two (2) years from the date of receipt
of the said report by the President and the President and the Working
Interest Owners shall, where necessary, take appropriate action with
regard to any matter arising out of the Auditor General's report.
19.2 The President or any non-Operator shall have the right, at its sole
cost to audit the Joint Account and related records for any Calendar
Year or portion thereof within two (2) years of the date of the
receipt of audit report provided in accordance with Article 19.1 with
respect to such Calendar Year, provided that thirty (30) days advance
notice is given to the Operator.
[PAGE # ... 50]
<PAGE> 56
ARTICLE - XX
PRODUCTION BONUSES
20.1 With respect to Petroleum produced and saved from the Badin-II Revised
Area, the Private Working Interest Owners, shall pay the Government on
a Badin-II Revised Area basis, the following production bonuses:
BONUS AMOUNT CUMULATIVE
IN US DOLLARS PRODUCTION
FROM THE BADIN-II
REVISED AREA
(MMBOE)
$500,000 On Commencement
of Commercial
Production from the
Badin-II Revised Area
$1,000,000 30
$1,500,000 60
$3,000,000 80
$5,000,000 100
20.2 Pakistani Working Interest Owners other than OGDC and Government
Holdings will pay their share of production bonuses in Pakistani
Rupees.
20.3 Subject to the application of Article 6.4 of the Joint Operating
Agreement, payments due under Article 20.1 shall be made within sixty
(60) days after the occurrence of the first Commercial Production in
the Badin-II Revised Area and the remaining bonuses shall be payable
within sixty (60) days after each cumulative level of production as
set forth in Article 20.1 has been attained with respect to Petroleum
production from the Badin- II Revised Area. As long as the Government
is OGDC's majority shareholder, OGDC will not be subject to production
bonuses payable in accordance with the provisions of this Article XX.
However, once the Government no longer owns a majority of the
outstanding shares of OGDC, OGDC shall be obligated to pay its
Badin-II Revised Working Interest share of the production bonuses as
required by this Article.
20.4 Payments made under this Article XX are not to be amortized, expensed
or credited for Pakistani Income Tax purposes.
[PAGE # ... 51]
<PAGE> 57
ARTICLE - XXI
INSURANCE
21.1 The Operator shall comply with all workmen's compensation and
employers' liability laws and other insurance laws of Pakistan. The
Operator shall also take out such insurance for the benefit of the
Joint Account of the parties, naming them as insured parties, as may
be determined by representatives of the parties. The Operator shall
require all contractors engaged in work in the Badin-II Revised Area
under this Agreement to similarly comply with such insurance as the
Operator may require.
21.2 The Working Interest Owners shall in accordance with Rule 70 of the
Rules, during the term of this Agreement, indemnify, defend and hold
the President and the Government effectively indemnified against all
proceedings, costs, charges, claims, losses, damages and demands
whatsoever, including, without limitation, claims for loss or damage
to property or injury or death to persons, caused by or resulting from
any Joint Operations conducted by or on behalf of the Working Interest
Owners; provided, however, that the Working Interest Owners shall not
be held responsible to the Government under this Article for any loss,
claim, damage or injury caused by or resulting from any negligent act
or wilful misconduct by personnel of the President and/or Government
or from any action of or against the President and/or Government. Any
obligation to indemnify the Government arising under this Agreement
shall be borne by the Working Interest Owners in proportion of their
respective Badin-II Revised Working Interest determined at the time of
the event or occurrence giving rise to the obligation to indemnify the
President and/or Government.
21.3 At the request of the President, the Working Interest Owners shall
provide evidence of any insurance required pursuant to this Agreement.
[PAGE # ... 52]
<PAGE> 58
ARTICLE - XXII
TRAINING, EMPLOYMENT AND SOCIAL WELFARE
22.1 The Operator agrees to employ qualified nationals of Pakistan for
Joint Operations and, to undertake schooling and training for staff
positions, including administrative and executive management
positions. Preference will be given to employment of nationals and
unskilled workers from the Badin-II Revised Area. The Operator will
require its contractors and subcontractors, operating in Pakistan, to
do the same. The Operator undertakes to gradually replace its
expatriate staff with qualified nationals as they become available. An
annual programme for employment and training of nationals of Pakistan
shall be determined by the Operator in consultation with the Director
General Petroleum Concessions. Such programme shall be included in the
annual work programme and budget.
22.2 Within thirty (30) days of the end of each Calendar Year, the Operator
shall submit a written report to DGPC describing the number of
personnel employed, their nationality and positions and the status of
training programmes for nationals of Pakistan.
22.3 The Operator may also be required in accordance with Rule 61(2) of the
Rules to establish a programme, satisfactory to the President, to
train government personnel locally and abroad to develop the
capability of such personnel to effectively perform their duties
related to the supervision of the Petroleum industry. Such training
programme shall cover both technical and management disciplines (e.g.,
geology, geophysics, engineering, project management, accounting,
legal) and shall include on-the-job training and participation in
in-house seminars.
22.4 The Private Working Interest Owners, shall, in the aggregate spend for
training a minimum US Dollars $10,000 per Calendar Year prior to the
date of the first Commercial Production. Commencing with the date of
first Commercial Production the minimum Expenditures for training in
each Calendar Year shall be increased to US$25,000 per Calendar Year.
This Expenditure will be subject to upward review from time to time.
The unspent training amount during a Calendar Year unless agreed
otherwise shall be deposited into a special account maintained for
that purpose by the DGPC.
22.5 For each Calendar or portion thereof during the term of this
Agreement, the Private Working Interest Owners shall expend the
amounts set forth herein for the social welfare of the communities in
and around the Badin-II Revised Area.
[PAGE # ... 53]
<PAGE> 59
Prior to Commercial Production from the Badin-II Revised Area, the
Private Working Interest Owners shall, in the aggregate, expend a
minimum of US$20,000 per Calendar Year. After Commercial Production
the Private Working Interest Owners shall, in the aggregate, expend
the minimum amounts set opposite the daily average rate of production
from the Badin-II Revised Area attained for the Calendar Year for
which such payment is to be made.
<TABLE>
<CAPTION>
BADIN-II REVISED AREA AMOUNT PER YEAR
RATE OF PRODUCTION (US DOLLARS)
(BOE/DAY)
<S> <C>
Less than 2,000 $20,000
2,001 - 5,000 $40,000
5,001 - 10,000 $75,000
10,001 - 50,000 $150,000
More than 50,000 $250,000
</TABLE>
22.6 All such Expenditures made pursuant with this Article XXII shall be
treated for Pakistani income tax purposes as wholly and exclusively
incurred for the purposes of the income under rule 2(3), 2(4) or 2(5)
of the Fifth Schedule, as may be applicable.
[PAGE # ... 54]
<PAGE> 60
ARTICLE - XXIII
DEVELOPMENT FINANCING
23.1 Subject to Article 11.9, any of the Working Interest Owners shall have
the right to obtain project financing for the development of any
Commercial Discovery made in the Badin-II Revised Area. The President,
upon request of a Working Interest Owner, shall, where possible, use
its good offices to assist in all things necessary to facilitate
project financing by a consortium of banks for any portion of the
development costs.
23.2 Subject to Article 11.9, any Working Interest Owner may, upon
informing the other Working Interest Owners and with the approval of
the President, which shall not be unreasonably withheld, mortgage and
pledge, by way of mortgage and hypothecation, any or all of its rights
hereunder, to secure the prompt payment of sums of money, principal
and interest, so borrowed, and the full and faithful discharge of any
and all obligations which it may undertake to obtain financing for the
purpose of this Agreement.
[PAGE # ... 55]
<PAGE> 61
ARTICLE - XXIV
PARENT COMPANY GUARANTEE
24.1 The Private Working Interest Owners shall on the Effective Date
furnish a parent company guarantee as per the format of Annexure-V.
[PAGE # ... 56]
<PAGE> 62
ARTICLE - XXV
EFFECTIVENESS AND DURATION
25.1 This Agreement shall be and remain in full force and effect commencing
on the Effective Date and so long thereafter as the Working Interest
Owners shall own any interest in the Badin-II Revised Licence or any
Lease granted with respect thereto, or until a final settlement has
been made after the Surrender of the entire Badin-II Revised Area,
expiration or termination of Petroleum rights granted under this
Agreement, the Badin-II Revised Licence or any Lease granted with
respect to the Badin-II Revised Licence.
[PAGE # ... 57]
<PAGE> 63
ARTICLE - XXVI
ROYALTY
26.1 The Working Interest Owners shall pay to the government a royalty
equal to twelve and one-half percent (12- 1/2%) of the Wellhead Value
of the Working Interest Owners' annual gross production of Petroleum
produced and saved in each Calendar Year from the Badin-II Revised
Area subject to the Rules and the other provisions of this Agreement.
26.2 Royalty shall be payable in cash and/or kind at the option of the
Government.
26.3 Royalty in cash shall be payable monthly within ten (10) days from the
date of the receipt of the invoice proceeds. Payment shall be
accompanied by a certificate from the Working Interest Owner setting
forth in detail the basis for computation of the royalty. Such
certificate shall be in a form acceptable to the Government.
26.4 From the amount of royalty payable in respect of a Lease, there shall
be deducted the amount of Lease rent paid for the corresponding
period.
26.5 For the purposes of determining the amount of the royalty due, the
Wellhead Value of the Petroleum shall be determined in accordance with
Article VII.
26.6 If the Government elects to take the royalty, or any part thereof, in
kind, it shall notify the Working Interest Owners in accordance with
the provisions of Article 26.7.
26.7 If the Government elects to take the royalty on Petroleum in kind, it
shall initially so notify the Operator in writing not less than six
(6) months prior to the commencement of deliveries of such Royalty
Petroleum, and thereafter not less than ninety (90) days prior to the
commencement of each six (6) month semester of each Calendar Year
specifying the quantity, and designating the grade and quality of
Royalty Petroleum that it elects to take, based upon the Operator's
estimates of production. Final adjustments shall be made within ninety
(90) days of the end of each Calendar Year on the basis of actual
quantifies. Such notice shall be effective for the ensuing six (6)
month semester of that Calendar Year. Failure to give such notice
shall be conclusively deemed to evidence the election by the
Government not to take any Royalty Petroleum.
[PAGE # ... 58]
<PAGE> 64
26.8 Royalty Petroleum shall be delivered by the Operator, free of cost to
the Government subject to Article 27.5, at regularly spaced intervals
at the field terminal unless otherwise agreed. The Government shall
provide at the field terminal, at its sole expense, all storage,
transportation and other facilities necessary to receive such Royalty
Petroleum; provided, however, that if production of Petroleum is not
unreasonably impaired, the Government may use twelve and one-half
percent (12-1/2%) of field tank storage capacity for storage of
Royalty Petroleum free of charge; and if additional storage capacity
is available and is not required for Joint Operations and is utilized
to store Royalty Petroleum, the Government shall pay the Working
Interest Owners at the current rate for such field storage, and if no
such current rate is established, then at a fair rate to be agreed
upon in the light of accepted oil field practices.
26.9 Each of the Private Working Interest Owners shall deliver to the
Government, at the time that the audit report required under 19.1 is
delivered, a certificate prepared by their respective chartered
accountants that certifies for its Working Interest, for the year to
which the certificate relates that (i) its depletion allowance has
been calculated using Wellhead Value for tax purposes determined in
accordance with the applicable tax laws, (ii) its royalty has been
valued using the Wellhead Value in accordance with the Rules and this
Agreement, (iii) its processing charges on royalty, if paid, have been
deducted from its operating expenses or declared as "other income" for
tax purposes, and (iv) the amounts described in clauses (i), (ii) and
(iii) have been reflected in its audited accounts.
[PAGE # ... 59]
<PAGE> 65
ARTICLE - XXVII
MISCELLANEOUS
27.1 The Operator shall conduct all exploration, exploitation, drilling,
development, production and other operations hereunder in accordance
with this Agreement the Joint Operating Agreement, the Rules and good
oilfield practices. Consistent with this requirement the Operator
shall endeavour to minimize exploration, development, production and
operating costs and to maximize the ultimate economic recovery of
Petroleum from the Badin-II Revised Area.
27.2 The Operator shall not start production from any well before testing
and making sure to the reasonable satisfaction of the President's
representative, that the well has been properly completed in
accordance with the Rules and good oilfield practices.
27.3 In connection with Operations provided for and described in this
Agreement, the Operator shall use the helicopters of Pakistan
International Airlines Corporation or other Government agencies, as
needed, provided such helicopters are suitable in the opinion of
Operator and available on terms comparable to those offered by
international operators in comparable areas.
27.4 If the President elects to receive the royalty in kind as provided in
accordance with Rule 37 of the Rules, the Working Interest Owners
shall deliver the Royalty Petroleum at the nearest operating refinery
or main transmission system, as the case may be, at the cost to the
Government for transportation, treatment and storage or as the
Government may reasonably require, in the same manner as if it were
the Working Interest Owners' Petroleum.
27.5 So long as production of Petroleum programmed by the Working Interest
Owners is not unreasonably impaired the President may use twelve and
one-half percent (12-1/2%) of the field tank storage capacity owned
jointly by the Working Interest Owners hereunder for storage of
Royalty Petroleum (other than Natural Gas) free of charge. If
additional storage capacity is available and is not required by the
Working Interest Owners and is utilized to store the President's
Royalty Petroleum, the President shall pay the Working Interest Owners
therefor at the current rate of storage in the oil fields and, if
there shall be no current rate established, then at a fair rate to be
agreed upon in the light of accepted oilfield practices.
[PAGE # ... 60]
<PAGE> 66
27.6 All pipeline and Crude Oil terminal facilities owned jointly by the
Working Interest Owners hereunder shall be reserved for the
transportation of Petroleum produced by the Working Interest Owners
hereunder; provided, however, that to the extent, from time to time,
there is throughput capacity of the Working Interest Owners not being
utilized, such pipeline capacity may be used by the President for
Petroleum purchased from the Working Interest Owners and by other
Petroleum concessionaires in Pakistan, all of whom shall pay the
Working Interest Owners for such use a fee computed on a unit
volume/distance basis after taking into consideration the cost of
construction, operating and maintaining such pipeline or pipelines,
including depreciation thereof, and applicable taxes, and, for users
other than the President, a reasonable profit. The Working Interest
Owners shall not be responsible for the loss during transportation or
storage of Petroleum belonging to the President. Income derived from
such transportation and storage shall be governed by the Fifth
Schedule to the Income Tax Ordinance, 1979, as in force on the
Effective Date. The Working Interest Owners shall be entitled to form
a separate company for the ownership and operation of any such
pipeline or Petroleum terminal facility.
27.7 This Agreement shall be governed by and shall be given effect under
the laws of Pakistan.
27.8 This Agreement sets forth the entire agreement reached between the
Working Interest Owners and The President and it shall remain and
continue in force and shall be binding upon each of them throughout
its duration without any amendment, revision or alteration thereto
except as may hereafter be mutually agreed by the Working Interest
Owners with the approval of the President, and the Rules, Income Tax
Ordinance 1979, Regulation of Mines and Oilfields and Mineral
Development (Government Control) Act, 1948 and other laws as in force
on the Effective Date shall remain applicable for purposes hereof,
whether or not they are subsequently amended or revised; provided,
that where any matter is not specifically dealt with in this
Agreement, such matter shall be governed in accordance with the
applicable provision of the Rules, Income Tax Ordinance 1979,
Regulation of Mines and Oilfields and Mineral Development (Government
Control) Act, 1948 and other laws as in force on the Effective Date of
this Agreement.
27.9 Notices and other communications required to be given under this
Agreement shall be considered as properly given if written in the
English language and delivered to the addresses respectively shown
below:
[PAGE # ... 61]
<PAGE> 67
a] In the case of the President to:
The Secretary Ministry of Petroleum and Natural Resources,
3rd Floor, Secretariat Block "A"
lslamabad.
Telephone : (92-51) 211220
Telex : 5862 PETNR PK
b] In the case of Government Holdings to:
The Director General Petroleum Concessions,
Department of Petroleum and Energy Resources,
Ministry of Petroleum and Natural Resources,
1019-A 19-A, Pak. Plaza,
Fazal-e-Haq Road,
Blue Area,
Islamabad (Pakistan).
Attention : Director General Petroleum Concessions,
Telephone : (92-51) 824993
Telex : 54089 TWPET PK
c] In the case of Union Texas to:
Union Texas Pakistan, Inc.
3rd Floor, Bahria Complex
24 Moulvi Tamizuddin Khan Road
Karachi-74000 (Pakistan).
Attention : President
Telephone : (92-21) 5610638, 5610205, 5611194,
Telex : 25258, 29498 UNOTX PK
[PAGE # ... 62]
<PAGE> 68
d] In the case of Occidental to:
Occidental Petroleum (Pakistan), Inc.
47-N, Dossal Arcade
Blue Area
Islamabad (Pakistan).
Attention : President & General Manager
Telephone : (92-51) 214261
Telex : 695 OXY IS
e] In the case of OGDC to:
Oil and Gas Development Corporation
Masood Mansion, F-8, Al-Markaz
Islamabad (Pakistan).
Attention : Chairman
Telephone : (92-51) 8500213
Telex : 5867 OGDC PK, 5692 OGDC PK
Any party may change its address by notifying all other parties thereof in
writing at least ten (10) days before the effective date of such change.
27.10 This Agreement shall inure to the benefit of and be binding upon the
respective successors and permitted assignees of the Working Interest
Owners hereto.
27.11 All headings used herein are for the purpose of reference only and
shall not be construed as in any way defining or limiting the meaning
of any provision.
27.12 The President hereby approves, on behalf of the Government, the
foreign private investment to be made by Union Texas and Occidental
and their respective assignees pursuant to this Agreement for purposes
of the issuance of such investment insurance and other investment
incentives as may be available to the Private Working Interest Owners
and their respective assignees from Overseas Private Investment
Corporation, an agency of the United States Government or its
successors.
[PAGE # ... 63]
<PAGE> 69
27.13 All the rules, laws, regulations in effect on the Effective Date,
including the Workers' Welfare Fund Ordinance, 1971 and the Companies
Profits (Workers' Participations) Act, 1968, shall apply to this
Agreement throughout its term whether or not such Rules, Laws and
regulations are subsequently amended, repealed or replaced.
27.14 The Operator shall observe all laws, rules and regulations issued by
the Government in respect of protection of the environment and safety
of operations, including the Mines Act, 1923, the Oil and Gas (Safety
in Drilling and Production Regulations, 1974, the Territorial Waters
and Maritime Zone Act 1976 and the Pakistan Environmental Protection
Ordinance, 1983.
27.15 The Working Interest Owners and the Government will enter into an
amendment of the Badin-II PCA to incorporate into the Badin-II PCA the
definition of "Lease" as it appears in Article 1.38 of this Agreement
and to incorporate such other provisions so as to give effect to that
change.
IN WITNESS WHEREOF, this Agreement has been duly executed by the respective
parties hereto this 17th day of December, 1994.
FOR AND ON BEHALF OF
THE PRESIDENT OF THE ISLAMIC
REPUBLIC OF PAKISTAN
BY: /s/ UNREADABLE
-----------------------------
NAME: Unreadable
---------------------------
TITLE: Unreadable
--------------------------
WITNESSES:
1. /s/ UNREADABLE
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2. /s/ UNREADABLE
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(TO NEXT PAGE)
[PAGE # ... 64]
<PAGE> 70
(SIGNATURE PAGE CONTINUED)
UNION TEXAS PAKISTAN, INC.
BY: /s/ J.E. KENNEDY
------------------------------
NAME: J.E. Kennedy
----------------------------
TITLE: President
---------------------------
WITNESSES:
1. /s/ UNREADABLE
-------------------------------
2. /s/ UNREADABLE
-------------------------------
OCCIDENTAL PETROLEUM (PAKISTAN), INC.
BY: /s/ UNREADABLE
------------------------------
NAME: UNREADABLE
----------------------------
TITLE: UNREADABLE
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WITNESSES:
1. /s/ UNREADABLE
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2. /s/ UNREADABLE
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(TO NEXT PAGE)
[PAGE # ... 65]
<PAGE> 71
(SIGNATURE PAGE CONTINUED)
OIL AND GAS DEVELOPMENT CORPORATION
BY: /s/ UNREADABLE
------------------------------
NAME: Unreadable
----------------------------
TITLE: Unreadable
---------------------------
WITNESSES:
1. /s/ UNREADABLE
--------------------------------
2. /s/ UNREADABLE
--------------------------------
THE FEDERAL GOVERNMENT OF THE
ISLAMIC REPUBLIC OF PAKISTAN
BY: /s/ UNREADABLE
------------------------------
NAME: Unreadable
----------------------------
TITLE: Unreadable
---------------------------
WITNESSES:
1. /s/ UNREADABLE
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2. /s/ UNREADABLE
-------------------------------
[PAGE # ... 66]
<PAGE> 72
BADIN-II REVISED PETROLEUM CONCESSION AGREEMENT
The following describes Annexures to the Badin-II Revised Petroleum Concession
Agreement, which are omitted herein, but will be furnished upon request:
Annexure-I:
Map of Badin-II Revised Area (identifying areas under Badin-II
Revised Petroleum Concession Agreement) Annexure-II:
Badin-II Revised Joint Operating Agreement
Annexure-III:
Standard Form of Development and Production Lease
Annexure-IV:
(regarding the import/export of machinery and equipment and
other goods)
Exhibit A: SRO 367(I)/94 Dated May 9, 1994
Exhibit B: CGO-2/93 Dated May 20, 1993
Exhibit C: SRO 336(I)/94 Dated April 26, 1994
Exhibit D: List of Machinery, Equipment, Materials, Vehicles,
Accessories, Spares, Chemicals and Consumables, Etc.
Exhibit E: SRO 366(I)/94 Dated May 9, 1994
Exhibit F: Central Board of Revenues Letter
C.No.10(14)/93-ICM-CON Dated June 13, 1994
Exhibit G: List of Commissary Stores
Annexure-V:
Parent Company Guarantee
Exhibit A to Joint Operating Agreement (Badin-II Revised Accounting
Procedures)
[PAGE # ... 67]
<PAGE> 1
SUBSIDIARIES OF THE REGISTRANT
Except as otherwise noted, Union Texas Petroleum Holdings, Inc. (the "Company")
holds, either directly or indirectly, all or substantially all of the voting
stock of the following corporations. Except as otherwise noted, all of the
corporations are incorporated in the state of Delaware.
Union Texas Asia Corporation
Union Texas Acadia Corporation
Union Texas Barakan, Inc.
Union Texas Brasil, Inc.
Union Texas Carthage, Inc.
Union Texas Egypt, Inc.
West Gemsa Petroleum Company (1)
Four Oaks Insurance, Ltd. (2)
Union Texas Petroleum Energy Corporation
Unicon Producing Company (3)
Union Texas International Corporation
Union Texas Adriatic, Inc.
Union Texas (Argentina) Ltd.
Union Texas Energy Development Limited (5)
Union Texas Finance, Inc.
Union Texas Maghreb, Inc.
Union Texas Methane, Inc.
Union Texas (Kai) Limited (4)
Union Texas (Tanimbar) Limited (4)
Union Texas (Rebi) Limited (4)
Union Texas (Transnational) Limited (4)
Union Texas East Kalimantan Limited (4)
Union Texas Espana, Inc.
Union Texas PNG, Inc.
Union Texas Pakistan, Inc.
Union Texas Petroleum Limited (5)
Union Texas Britannia Limited (5)
Union Texas Trading Corporation
Union Texas Transportation Limited (5)
Union Texas Metropole, S.A. (6)
Union Texas Petroleum Alaska Corporation
Union Texas Petroleum Services Corporation
Union Texas Products Corporation
Union Texas I Corporation
Union Texas Petrochemicals Pipeline, Inc.
Union Texas Power Development Limited (4)
Union Texas South Atlantic, Inc.
Union Texas South Pacific, Inc.
Union Texas (South East Asia) Inc.
Union Texas Tunisia, Inc.
Union Texas Venezuela Limited (4)
Unistar, Inc.
-1-
<PAGE> 2
Union Texas Development Corporation
Unimar Company (7)
ENSTAR Corporation (8)
VICO 7.5, Inc. (8)
Virginia Indonesia Company (8)
Virginia Services, Ltd. (8)
Purchasing Services Inc. (8)
VICO Services, Inc. (8)
VICO Enterprises, Inc. (8)
ENSTAR Indonesia, Inc. (8)
Virginia International Company (8)
VICO Trading, Inc. (8)
Alaska Interstate Int'l Finance, N.V. (8)(9)
Alaska Interstate Int'l Finance, B.V. (8)(10)
AKI International Finance, N.V. (8)(9)
ENSTAR Petroleum, Ltd. (8)(11)
Unimar Financing Corporation (8)
____________________________________
(1) Incorporated under the laws of Egypt.
(2) Incorporated under the laws of Bermuda.
(3) A Texas general partnership between a subsidiary of the Company and
Continental Can Europe, Inc.
(4) Incorporated under the laws of the Bahamas.
(5) Incorporated under the laws of the United Kingdom.
(6) Incorporated under the laws of France.
(7) A Texas general partnership between a subsidiary of the Company and a
subsidiary of LASMO plc, a U.K. company.
(8) Direct or indirect subsidiary of Unimar Company.
(9) Incorporated under the laws of Curacao, Netherlands Antilles.
(10) Incorporated under the laws of Rotterdam, The Netherlands.
(11) Incorporated under the laws of Alberta, Canada.
-2-
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
COMPANY'S SEC FORM 10-K FOR THE PERIOD ENDING DECEMBER 31, 1995 AND IS QUALIFIED
IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C> <C>
<PERIOD-TYPE> YEAR YEAR
<FISCAL-YEAR-END> DEC-31-1995 DEC-31-1994
<PERIOD-END> DEC-31-1995 DEC-31-1994
<CASH> 11,069 8,389<F1>
<SECURITIES> 0 0
<RECEIVABLES> 77,593 54,776
<ALLOWANCES> 76 3
<INVENTORY> 42,764 43,228
<CURRENT-ASSETS> 159,274 137,065
<PP&E> 2,851,254 2,426,863
<DEPRECIATION> 1,300,056 1,140,585
<TOTAL-ASSETS> 1,836,818 1,544,634
<CURRENT-LIABILITIES> 195,543 181,504
<BONDS> 712,132 536,117
<COMMON> 4,391 4,391
0 0
0 0
<OTHER-SE> 419,399 345,108
<TOTAL-LIABILITY-AND-EQUITY> 1,836,818 1,544,634
<SALES> 851,601 747,883
<TOTAL-REVENUES> 876,029 769,595
<CGS> 299,133 299,586
<TOTAL-COSTS> 516,734 492,681
<OTHER-EXPENSES> 77,185 53,532
<LOSS-PROVISION> 0 0
<INTEREST-EXPENSE> 28,783 11,399
<INCOME-PRETAX> 253,327 211,983
<INCOME-TAX> 150,977 145,245
<INCOME-CONTINUING> 102,350 66,738
<DISCONTINUED> 0 0
<EXTRAORDINARY> 0 0
<CHANGES> 0 0
<NET-INCOME> 102,350 66,738
<EPS-PRIMARY> 1.17 .76
<EPS-DILUTED> 0 0
<FN>
<F1>Certain data for the period and year ending December 31, 1994 have been
reclassified for comparative purposes.
</FN>
</TABLE>
