-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, LFvaMFbKjinsM+T7ARj2SbNgTYehGxvr9JXaYNFl/F/DVi8X/Km4chSkde2O5scm vzU2OkSgmmLF/H+1G3ReOQ== 0000950129-96-000354.txt : 19960314 0000950129-96-000354.hdr.sgml : 19960314 ACCESSION NUMBER: 0000950129-96-000354 CONFORMED SUBMISSION TYPE: 10-K405 PUBLIC DOCUMENT COUNT: 8 CONFORMED PERIOD OF REPORT: 19951231 FILED AS OF DATE: 19960313 SROS: NYSE SROS: PSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: UNION TEXAS PETROLEUM HOLDINGS INC CENTRAL INDEX KEY: 0000774214 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 760040040 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K405 SEC ACT: 1934 Act SEC FILE NUMBER: 001-09019 FILM NUMBER: 96534290 BUSINESS ADDRESS: STREET 1: 1330 POST OAK BLVD CITY: HOUSTON STATE: TX ZIP: 77056 BUSINESS PHONE: 7136236544 MAIL ADDRESS: STREET 1: 1330 POST OAK BLVD CITY: HOUSTON STATE: TX ZIP: 77056 10-K405 1 UNION TEXAS PETROLEUM HOLDINGS, INC. 12/31/95 1 - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- 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:
NAME OF EACH EXCHANGE TITLE OF EACH CLASS ON WHICH REGISTERED ---------------------------------- ---------------------------------- Common Stock, $.05 par value New York Stock Exchange Pacific Stock Exchange 8.25% Senior Notes due 1999 New York Stock Exchange
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. - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- 2 TABLE OF CONTENTS
PAGE ---- 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
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 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 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):
AS OF OR FOR THE YEAR ENDED DECEMBER 31, ---------------------------- 1995 1994 1993 ------ ------ ------ (DOLLARS IN MILLIONS) 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
- --------------- (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 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.
OIL EQUIVALENTS OIL (MBBLS)(A)(B) GAS (MMCF)(B) (MBOE)(A)(B) ------------------------------- -------------------------------- -------------------------------- DEVELOPED UNDEVELOPED TOTAL DEVELOPED UNDEVELOPED TOTAL DEVELOPED UNDEVELOPED TOTAL --------- ----------- ------- --------- ----------- -------- --------- ----------- ------- 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 ====== ====== ======= ========= ======= ========= ======= ======= =======
- --------------- (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 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 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:
EQUITY UNITED PARTNERSHIP KINGDOM INDONESIA PAKISTAN INDONESIA ------- --------- -------- ----------- 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)
- --------------- (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:
EQUITY UNITED PARTNERSHIP KINGDOM INDONESIA PAKISTAN INDONESIA ------- --------- -------- ----------- 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)
- --------------- (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 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.
DEVELOPED ACRES UNDEVELOPED ACRES --------------- ------------------- GROSS NET GROSS NET ----- --- ------ ------ (NUMBERS IN THOUSANDS) 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 === == ====== ======
- --------------- (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.
OIL WELLS GAS WELLS ------------------ ------------------ AREA GROSS NET GROSS NET --------------------------------------------- ----- ------ ----- ------ 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 === ===== ==== ======
- --------------- (a) The Company also has a direct interest in such wells, which is included above in the Company's gross wells for Indonesia. 7 10 The net productive and dry exploratory wells drilled during 1995, 1994 and 1993, by geographic area, were as follows:
EXPLORATORY WELLS ------------------------------------------------- PRODUCTIVE DRY ---------------------- ---------------------- AREA 1995 1994 1993 1995 1994 1993 ----------------------------------------- ---- ---- ---- ---- ---- ---- 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 ==== ====
The net productive and dry development wells drilled during 1995, 1994 and 1993, by geographic area, were as follows:
DEVELOPMENT WELLS -------------------------------------------------- PRODUCTIVE DRY ----------------------- ---------------------- AREA 1995 1994 1993 1995 1994 1993 ----------------------------------------- ---- ---- ----- ---- ---- ---- 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 ==== ==== ===== === === ===
At December 31, 1995, wells in progress were as follows:
EXPLORATORY DEVELOPMENT ---------------- ---------------- GROSS NET GROSS NET ----- ---- ----- ---- 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 == ==== == ====
- --------------- (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 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 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 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 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 15 The following table sets forth information regarding the Bontang LNG plant's share of LNG sales contracts at December 31, 1995:
JOINT VENTURE'S REMAINING SHARE OF LNG REMAINING SALES LNG SALES CONTRACT VOLUMES JOINT VENTURE VOLUMES TERM (TBTU) PARTICIPATION % (A)(B) (TBTU) (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
- --------------- (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 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 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. 15 18 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. 16 19 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 17 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- 18 21 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 19 22 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 20 23 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" 21 24 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 22 25 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 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:
1995 1994 ------------------------------------------------------------------- ------------------------------- QUARTER ENDED QUARTER ENDED ------------------------------------------------------------------- ------------------------------- MARCH 31 JUNE 30 SEPT. 30 DEC. 31 MARCH 31 JUNE 30 ------------- ------------- ------------- ------------- ------------- ------------- 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 1994 ------------------------------- QUARTER ENDED ------------------------------- SEPT. 30 DEC. 31 ------------- ------------- High.......... 20 3/8 21 7/8 Low........... 17 18 1/8
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 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.
YEAR ENDED DECEMBER 31, --------------------------------------------------------------------- 1995 1994 1993 1992 1991 ----------- ---------- ---------- --------- ----------- (DOLLARS IN THOUSANDS EXCEPT PER SHARE AMOUNTS) 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
- --------------- (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 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:
VOLUMES PRICES (000S PER DAY) --------------------- ------------------- 1995 1994 1995 1994 ------ ------ ----- ----- 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
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 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 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 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 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 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 34 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. INDEX TO FINANCIAL STATEMENTS
PAGE ---- 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
32 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 36 UNION TEXAS PETROLEUM HOLDINGS, INC. CONSOLIDATED BALANCE SHEET (DOLLARS IN THOUSANDS) ASSETS
DECEMBER 31, ------------------------- 1995 1994 ---------- ---------- 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 ========== ==========
- --------------- * 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 37 UNION TEXAS PETROLEUM HOLDINGS, INC. CONSOLIDATED STATEMENT OF OPERATIONS (DOLLARS IN THOUSANDS EXCEPT PER SHARE AMOUNTS)
YEAR ENDED DECEMBER 31, ---------------------------------- 1995 1994 1993 -------- -------- -------- 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 ======== ======== ========
The accompanying notes are an integral part of this financial statement. 35 38 UNION TEXAS PETROLEUM HOLDINGS, INC. CONSOLIDATED STATEMENT OF CASH FLOWS (DOLLARS IN THOUSANDS)
YEAR ENDED DECEMBER 31, ----------------------------------- 1995 1994 1993 --------- --------- --------- 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
The accompanying notes are an integral part of this financial statement. 36 39 UNION TEXAS PETROLEUM HOLDINGS, INC. CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY (DOLLARS IN THOUSANDS)
YEAR ENDED DECEMBER 31, ----------------------------------------- 1995 1994 1993 ----------- ----------- ----------- 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) =========== =========== ===========
The accompanying notes are an integral part of this financial statement. 37 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 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 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:
1995 1994 ------- ------- 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 ======= =======
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:
1995 1994 ------- ------- Products......................................................... $16,225 $11,307 Materials and supplies........................................... 26,539 31,921 ------- ------- $42,764 $43,228 ======= =======
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:
1995 1994 -------- -------- Unimar Company................................................. $108,476 $114,505 ======== ========
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 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:
1995 1994 1993 -------- ------- -------- 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 ======== ======= ========
1995 1994 -------- -------- Current assets............................................. $ 12,754 $ 12,226 Total assets............................................... 203,607 211,090 Current liabilities........................................ 15,731 15,281 Partners' account.......................................... 102,533 109,124
NOTE 6 -- PROPERTY, PLANT AND EQUIPMENT At December 31, 1995 and 1994, property, plant and equipment consisted of the following:
1995 1994 ---------- ---------- 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 ========== ==========
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 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:
1995 1994 -------- -------- 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 ======== ========
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 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 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
YEAR ENDED DECEMBER 31, --------------------------------- 1995 1994 1993 -------- -------- --------- 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) ======== ========= ==========
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:
YEAR ENDED DECEMBER 31, -------------------------------- 1995 1994 1993 -------- -------- -------- 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) ======== ======== ========
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 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:
YEAR ENDED DECEMBER 31, ----------------------- 1995 1994 -------- -------- 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 ======== ========
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:
SUPPLEMENTAL PENSION PLAN RETIREMENT PLANS -------------------- ------------------ 1995 1994 1995 1994 -------- -------- ------- ------- 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) ======== ======== ======= =======
45 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:
1995 1994 1993 --------- --------- --------- 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 ========= ========= =========
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:
1995 1994 -------- -------- 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) ======== ========
Net postretirement benefit cost for 1995, 1994 and 1993 included the following components:
1995 1994 1993 ------- ------- ------- 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) ======= ======= =======
46 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.
NUMBER OF SHARES --------------------- 1995 1994 --------- -------- 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 ========= =========
- --------------- *298,700 shares granted in 1994 were granted with stock appreciation rights. 47 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.
NUMBER OF SHARES -------------------- 1995 1994 -------- -------- 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 ======= =======
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.
NUMBER OF SHARES -------------------- 1995 1994 -------- -------- 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 ======= =======
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 51 UNION TEXAS PETROLEUM HOLDINGS, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (DOLLARS IN THOUSANDS UNLESS OTHERWISE INDICATED) NOTE 13 -- SEGMENT FINANCIAL DATA
EXPLORATION AND PRODUCTION ------------------------------------------------------ PETRO- UNITED OTHER CHEM- STATES UNITED INTER- ICALS (ALASKA) KINGDOM INDONESIA PAKISTAN NATIONAL (A) OTHER(A) TOTAL ------- ------- --------- -------- -------- ------ -------- ----- (DOLLARS IN MILLIONS) 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
- --------------- (a) Petrochemicals operations and Other represent United States activities. 49 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)
1995 1994 QUARTER ENDED QUARTER ENDED ----------------------------------------------------- ----------------------------------------------------- MAR. 31 JUNE 30 SEPT. 30 DEC. 31 YEAR MAR. 31 JUNE 30 SEPT. 30 DEC. 31 YEAR -------- -------- --------- -------- -------- -------- -------- --------- -------- -------- 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
- --------------- 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 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 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
CONSOLIDATED SUBSIDIARIES -------------------------------------------------------- NON- UNITED OTHER CONSOLIDATED TOTAL KINGDOM INDONESIA PAKISTAN INTERNATIONAL TOTAL INTERESTS WORLDWIDE ------- --------- -------- ------------- ------- ------------ --------- (THOUSANDS OF BARRELS) 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
52 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
CONSOLIDATED SUBSIDIARIES ------------------------------------------------ NON- UNITED CONSOLIDATED TOTAL KINGDOM INDONESIA PAKISTAN TOTAL INTERESTS WORLDWIDE ------- --------- -------- --------- ------------ --------- (MILLIONS OF CUBIC FEET) 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
- --------------- (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 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:
CONSOLIDATED SUBSIDIARIES -------------------------------------------------------- UNITED OTHER NON- TOTAL STATES UNITED INTER- CONSOLIDATED WORLD- (ALASKA) KINGDOM INDONESIA PAKISTAN NATIONAL TOTAL INTERESTS WIDE --------- ------- --------- -------- -------- ----- ------------ ------ (DOLLARS IN MILLIONS) 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
- --------------- (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 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:
CONSOLIDATED SUBSIDIARIES --------------------------------------------------------- UNITED OTHER NON- TOTAL STATES UNITED INTER- CONSOLIDATED WORLD- (ALASKA) KINGDOM INDONESIA PAKISTAN NATIONAL TOTAL INTERESTS WIDE --------- ------- --------- -------- -------- ------ ------------ ------ (DOLLARS IN MILLIONS) 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
55 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:
CONSOLIDATED SUBSIDIARIES ----------------------------------------------------------- UNITED OTHER NON- TOTAL STATES UNITED INTER- CONSOLIDATED WORLD- (ALASKA) KINGDOM INDONESIA PAKISTAN NATIONAL TOTAL INTERESTS WIDE -------- ------- --------- -------- -------- ---- ------------ ------ (DOLLARS IN MILLIONS) 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 ==== ===== ===== ==== ==== ==== ==== ====
- --------------- (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 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:
CONSOLIDATED SUBSIDIARIES ---------------------------------------- NON- TOTAL UNITED CONSOLIDATED WORLD- KINGDOM INDONESIA PAKISTAN TOTAL INTERESTS WIDE ------- --------- -------- ------- ------------ ------- (DOLLARS IN MILLIONS) 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 ======= ======= ==== ======= ====== =======
- --------------- (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 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:
1995 1994 1993 ------ ------ ------ (DOLLARS IN MILLIONS) 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 ====== ====== ======
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 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.
EXHIBIT NO. DESCRIPTION - --------------------- ------------------------------------------------------------------------ 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)
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EXHIBIT NO. DESCRIPTION - --------------------- ------------------------------------------------------------------------ 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)
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EXHIBIT NO. DESCRIPTION - --------------------- ------------------------------------------------------------------------ 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)
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EXHIBIT NO. DESCRIPTION - --------------------- ------------------------------------------------------------------------ 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)
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EXHIBIT NO. DESCRIPTION - --------------------- ------------------------------------------------------------------------ 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)
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EXHIBIT NO. DESCRIPTION - --------------------- ------------------------------------------------------------------------ 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)
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EXHIBIT NO. DESCRIPTION - --------------------- ------------------------------------------------------------------------ 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)
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EXHIBIT NO. DESCRIPTION - --------------------- ------------------------------------------------------------------------ 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)
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EXHIBIT NO. DESCRIPTION - --------------------- ------------------------------------------------------------------------ 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)
67 70
EXHIBIT NO. DESCRIPTION - --------------------- ------------------------------------------------------------------------ 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)
68 71
EXHIBIT NO. DESCRIPTION - --------------------- ------------------------------------------------------------------------ 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)
69 72
EXHIBIT NO. DESCRIPTION - --------------------- ------------------------------------------------------------------------ 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)
70 73
EXHIBIT NO. DESCRIPTION - --------------------- ------------------------------------------------------------------------ 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
- --------------- + Executive Severance Plan or Arrangement pursuant to Item 601(b)(10)(iii)(A) of Regulation S-K. # Filed herewith. 71 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 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.
SIGNATURE TITLE DATE --------- ----- ---- /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.)
73 76
SIGNATURE TITLE DATE --------- ----- ---- /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)
74 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 78 EXHIBIT INDEX
EXHIBIT NO. DESCRIPTION - --------------------- ------------------------------------------------------------------------ 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
EX-10.103 2 2ND AMEND. TO UTP SAVINGS PLAN FOR SALARIED EMP. 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." 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- 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- 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- 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- 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- EX-10.104 3 2ND AMEND. & RESTATED 1981 BADAK LNG SALES CONTR. 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 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 - --------------------------- --------------------------- 3 SECOND AMENDED AND RESTATED 1981 BADAK LNG SALES CONTRACT CONTENTS
Page 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
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. 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 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). 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. 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. 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. 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. 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. 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 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. 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). 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. 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. 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. 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"). 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. 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 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 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 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. 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"). 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. 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:
Calendar Fixed Quantity Fixed Quantities for Each Buyer Year Period (Billions of BTU's) - --------- ------------- ------------------------------------------------------------ Chubu Kansai Osaka Toho Total Electric Electric Gas Gas -------- ------- ------- ----- ------ 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
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). 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 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 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 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. 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 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 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 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. 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 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. 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. 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. 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 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. 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. 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. 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. 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: 45 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
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. 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. 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. 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. 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. 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. 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. 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; 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. 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. 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. 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. 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. 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. 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 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. 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. 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. 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. 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. 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. 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. 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 ------------------------- ------------------------- 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. 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. 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. 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 ------------------------- ------------------------- 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. EX-10.105 4 LNG SALES AND PURCHASE CONTRACT 8/12/95 1 LNG SALES AND PURCHASE CONTRACT (BADAK V) BETWEEN PERUSAHAAN PERTAMBANGAN MINYAK DAN GAS BUMI NEGARA (PERTAMINA) AND KOREA GAS CORPORATION 2 TABLE OF CONTENTS
PAGE 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
3 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
4 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
5 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
6 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
7 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
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 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 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 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. 4 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 5 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. 6 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. 7 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. 8 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 9 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. 10 18 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 11 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 12 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. 13 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. 14 22 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 15 23 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 16 24 ("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 17 25 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. 18 26 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. 19 27 (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). 20 28 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"). 21 29 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. 22 30 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: 23 31 (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 24 32 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. 25 33 (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 26 34 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. 27 35 (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. 28 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. 29 37 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. 30 38 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 31 39 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. 32 40 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. 33 41 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. 34 42 (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 35 43 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. 36 44 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. 37 45 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 38 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. 39 47 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 48 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
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. 41 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 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 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. 44 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 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 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 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. 48 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 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. 50 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 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 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 52 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 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 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 63 ARTICLE 23 - DETAILS OF PERFORMANCE Details necessary for performance of this Contract shall be mutually agreed upon by Seller and Buyer. 56 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. 57 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 execution hereof. 58 66 ARTICLE 26 - LANGUAGE OF THE CONTRACT This Contract is made and executed in the English language. 59 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 68 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. 61 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. EX-10.106 5 LNG SALES AND PURCHASE CONTRACT 10/25/95 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 2 TABLE OF CONTENTS
Page 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
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: 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. 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. 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. 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. 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. 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. 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. 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). 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. 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. 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. 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. 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. 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 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 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 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 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. 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; 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 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. 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. 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:
FIXED QUANTITY PERIOD FIXED QUANTITIES (CALENDAR YEAR) (BILLIONS OF BTUS) --------------- ------------------ 1998 5,187 1999 38,903 2000 88,179 2001-2017 95,500
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 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 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 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 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 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 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 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. 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. 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 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.$0.012/MMBTU. (b) An adjustment of the LNG Element to reflect any change in U.S.CPI shall be made on and shall be effective as of January 1 of each calendar year, and further adjustments of the LNG Element shall be made as of each effective date on which: (i) the realized export prices of more than one of the field classifications of Indonesian crude oils sold by PERTAMINA shall have changed from the respective prices therefor included in the last preceding determination of "A" made pursuant to Section 8.2(a); or (ii) two or more field classifications of such crude oils shall have been added to or deleted from the crude oils being sold by PERTAMINA since the date of the last preceding determination of "A" made pursuant to Section 8.2(a). Procedures for verifying changes in the realized export prices of all Indonesian crude oils and for determining the effective date of any adjustment of the LNG Element shall be separately agreed upon by the Parties. (c) The Parties shall agree separate procedures for handling corrections, revisions or changes in the calculation of U.S.CPI. It is agreed that if at any time the U.S. Department of Labor, Bureau of Labor Statistics discontinues publishing a report on U.S.CPI values, then the Parties shall agree upon an index method that reflects inflation in the United States of America's consumer prices to replace the discontinued U.S.CPI report. 37 8.3 Transportation Element for Fixed Quantity Periods beginning in 2000 The Transportation Element to be included in the Contract Sales Price shall be determined on, and with effect from, January 1, of each calendar year, in accordance with the following formula (expressed in U.S.$/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. 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. 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 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. 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 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. 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. 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. 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. 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 : 47 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
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. 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 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 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 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. 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. 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. 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 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. 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 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. 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. 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. 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. 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. 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. 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 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. 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. 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. 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 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. EX-10.107 6 BADIN-II REVISED PETROLEUM CONCESSION AGREEMENT 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] 2 BADIN-II REVISED PETROLEUM CONCESSION AGREEMENT TABLE OF CONTENTS
Page 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
(i) 3 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
(ii) 4 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
(iii) 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) 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] 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] 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] 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] 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] 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] 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] 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] 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] 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] 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:
RENEWAL MINIMUM WORK MINIMUM EXPENDITURE PERIOD PROGRAM (US DOLLARS) First Two (2) Exploration Wells 1,500,000 Second Two (2) Exploration Wells 1,500,000 Third One (1) Exploration Well 750,000
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] 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] 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] 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: 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
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] 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] 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] 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] 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] 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] 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] 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] 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] 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] 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] 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] 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] 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] 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] 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] 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] 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] 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] 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] 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] 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] 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] 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] 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] 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] 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] 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] 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] 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] 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] 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] 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] 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] 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] 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] 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] 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] 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] 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] 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.
BADIN-II REVISED AREA AMOUNT PER YEAR RATE OF PRODUCTION (US DOLLARS) (BOE/DAY) 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
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] 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] 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] 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] 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] 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] 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] 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] 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] 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] 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 ------------------------------- 2. /s/ UNREADABLE ------------------------------- (TO NEXT PAGE) [PAGE # ... 64] 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 --------------------------- WITNESSES: 1. /s/ UNREADABLE ------------------------------- 2. /s/ UNREADABLE ------------------------------- (TO NEXT PAGE) [PAGE # ... 65] 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 ------------------------------- 2. /s/ UNREADABLE ------------------------------- [PAGE # ... 66] 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] EX-21.1 7 SUBSIDIARIES OF THE REGISTRANT 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- 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- EX-27 8 FINANCIAL DATA SCHEDULE
5 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. 1,000 YEAR YEAR DEC-31-1995 DEC-31-1994 DEC-31-1995 DEC-31-1994 11,069 8,389 0 0 77,593 54,776 76 3 42,764 43,228 159,274 137,065 2,851,254 2,426,863 1,300,056 1,140,585 1,836,818 1,544,634 195,543 181,504 712,132 536,117 4,391 4,391 0 0 0 0 419,399 345,108 1,836,818 1,544,634 851,601 747,883 876,029 769,595 299,133 299,586 516,734 492,681 77,185 53,532 0 0 28,783 11,399 253,327 211,983 150,977 145,245 102,350 66,738 0 0 0 0 0 0 102,350 66,738 1.17 .76 0 0 Certain data for the period and year ending December 31, 1994 have been reclassified for comparative purposes.
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