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, 1994, the Company had proved oil and gas reserves of 411 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 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 28, 1995, the Company had approximately 1,000 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, 1994. 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 6 and 19 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 1994, Pertamina reached preliminary agreements for the extension of two of its long-term LNG sales contracts and for two new proposed long-term LNG sales contracts. To supply the additional quantities of LNG called for by the extensions, Pertamina has committed to construct a seventh processing train at the Bontang LNG facility and currently is conducting a feasibility study to determine the need for an eighth train to support the proposed new sales contracts. The construction of the seventh train will begin in 1995, and completion is expected in 1998. 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, Scapa, Saltire and Chanter oil fields, the Sean gas fields and the undeveloped Britannia gas and condensate field. The Company owns a 20% working interest in the Piper, Claymore, Chanter, Scapa and Saltire fields, which are operated by Elf Enterprise Caledonia Limited, and a 25% working interest in the Sean gas fields, which are operated by Shell U.K. Limited. The Sean gas fields include the North and South Sean fields and the recently discovered East Sean field. The Company acquired a 9.42% unit interest in the Britannia field in 1994 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. The Britannia acquisition resulted in the
addition at December 31, 1994, of proved undeveloped reserves of 38 million barrels of oil equivalent. 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 block began in 1982, and gas production began in 1989. The Company is the operator of the Pakistan joint ventures with working interests of 30% and 25.5% in the currently producing fields. The Company also bears 38% of the exploration costs and will receive a 25.5% working interest in any commercial discoveries in a new Badin concession area. In 1994, the Company was granted an exploration license and is currently negotiating 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 license.
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 prospects in Alaska, Argentina, Indonesia, Ireland, Italy, Pakistan, Tunisia, the United Kingdom and Vietnam.
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 facility processes gas liquids feedstocks to produce ethylene, a widely used petrochemical.
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 transactions that significantly streamlined its capital structure and reduced its financing costs. 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 entered into a $650 million unsecured credit facility and issued $100 million in principal amount of 8.25% senior notes due 1999. Since 1992, the Company has continued to strengthen its financial position by redeeming for $75 million plus accrued dividends its outstanding Preferred Auction Rate Stock during 1993 and by replacing its credit facility and increasing its short-term, uncommitted and unsecured lines of credit during 1994. The Company also improved its financing flexibility during 1994 with an effective shelf registration statement on file with the Securities and Exchange Commission that covers up to $200 million of debt securities that the Company may elect to offer in the future. For more information regarding these transactions, see Item 7 -- Management's Discussion and Analysis of Financial Condition and Results of Operations and Note 8 of Notes to Consolidated Financial Statements.
The Company's strategic focus is to build shareholder value through developing its core holdings, conducting an active exploration program, pursuing oil and gas acquisition opportunities and continuing to control costs. In January 1995, the Board of Directors of the Company approved a $212 million capital expenditure budget for 1995. Approximately one-third of the 1995 capital budget is allocated to fund the Company's expanded worldwide exploration program, which represents an 85% increase over exploration program funds expended in 1994. A total of $74 million is included in the Company's budget for exploration activities, including at least ten exploration wells in new venture areas in Alaska, Argentina, Eastern Indonesia, Ireland, Tunisia and Vietnam, and as many as 20 wells in ongoing exploration programs in the Company's producing areas in the U.K. North Sea, Indonesia and Pakistan. The budget also includes approximately $132 million for oil and gas development programs in the Company's producing areas, including $47 million for the initial development of the Britannia field. The Company has also budgeted approximately $5 million for its petrochemical interests in the United States. During 1995, the Company also intends to seek acquisition opportunities of both developed and undeveloped oil and gas reserves as well as to add to its production base in the near-term, amounts for which are not included in the capital spending budget. The Company will consider possible acquisition areas worldwide, including in the U.K. North Sea and Canada.
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. The KKR Partnerships currently own approximately 38% of the Company's issued and outstanding shares of common stock. See Note 1 of Notes to Consolidated Financial Statements.
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):
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(a) Net income (loss) and identifiable assets do not give effect to general and administrative items. See Note 14 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, 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 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. 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 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 and fires. Offshore operations are additionally subject to marine perils, including adverse weather conditions, 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 also subject to certain 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 Business Matters" below.
RESERVES
The following table sets forth information regarding the Company's estimates of its proved net reserves as of December 31, 1994. 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 19 of Notes to Consolidated Financial Statements.
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(a) For the purpose of calculating reserves, oil includes condensate and 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 (Notes continued on following page)
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.
(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 are subject to revision as prices fluctuate due to the cost recovery feature under the production sharing contract and 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 19 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. Projections about future prices and production levels are subject to great uncertainty. 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 19 of Notes to Consolidated Financial Statements.
The Company's reserve and production replacement strategy combines development drilling in proven areas with increased emphasis on worldwide exploration activities. The Company also continues to seek acquisitions to add proved developed and undeveloped reserves, such as the acquisition of the interest in the Britannia field in 1994. 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.
PRODUCTION
The following table sets forth the Company's average daily production of oil, natural gas liquids and gas during 1994, 1993 and 1992:
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(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 1994, 1993 and 1992 were as follows:
(See notes on following page)
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(a) Includes natural gas sold to a fertilizer plant and a refinery. The average sales price for LNG for 1994, 1993 and 1992 was $2.85, $3.17 and $3.41 per Mcf, respectively.
(b) Includes expenditures for operating expenses, severance and ad valorem taxes.
(c) Includes the impact of increases in volumes as a result of production from the Piper, Chanter and Saltire fields that came on stream in 1993.
(d) Includes plant processing costs and debt service on the Indonesian LNG processing facilities.
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 and domestic supplies of oil and gas, changing international economic and political conditions, domestic and foreign energy legislation, weather, environmental conditions, regulations and events, and actions of 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, 1994, 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.
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(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, 1994, 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 235.
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(a) The Company also has a direct interest in such wells, which is included above in the Company's gross wells for Indonesia.
The net productive and dry exploratory wells drilled during 1994, 1993 and 1992, by geographic area, were as follows:
The net productive and dry development wells drilled during 1994, 1993 and 1992, by geographic area, were as follows:
At December 31, 1994, wells in progress were as follows:
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(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, 1994, 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 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 1998. After conversion, the LNG is pumped into specially designed tankers (owned by third parties) and transported to purchasers, primarily 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 liquified petroleum gas ("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 the contract was extended in 1990, and is required to relinquish the following additional amounts: 10% by August 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 had an original term expiring in 1998, but in 1990, Pertamina and the joint venture amended the production sharing contract, extending the joint venture's right to explore, develop and produce oil and gas in the contract area until 2018. The amended production sharing contract, which generally contains terms and conditions similar to the production sharing contract prior to extension, 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 to receive, until September 25, 1999, a percentage of certain cash flow resulting from Unimar's interest in the joint venture. In 1994, approximately one-fourth of the Company's interest in such cash flow 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, 1994, proved reserves (net) attributable to the Company's total interest in the joint venture were approximately 1.4 Tcf of gas and 27 MMBbls of oil and condensate. The volumes of production required to recover the field, operating and capital depreciation costs of the joint venture are affected by prices received for such production. 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 prices fluctuate due to the cost recovery feature under the contract and due to the effect that price fluctuations generally have on estimates of recoverable reserves. See Note 19 of Notes to Consolidated Financial Statements.
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, 1994. 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 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 1994 and 1993, 23 and 29 successful development wells, respectively, were drilled in fields in East Kalimantan. During 1995, the Company expects to spend approximately $30 million on development drilling. 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 amended 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 in the future. Profits from gas supplied for domestic consumption, which was sold at an average price of $1.06 per Mcf in 1994, 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 1994.
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"). In 1994 and 1993, deliveries from the plant were 247 cargoes (108 Bcf net to the Company) and 217 cargoes (96 Bcf net to the Company) 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 cargoes per year (from 1.8 Bcf to 2.3 Bcf per day).
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.
With the completion of the sixth train and the debottlenecking project, the Bontang plant currently has additional unused processing capacity. 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.
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 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. Financings of the fifth and sixth trains are nonrecourse to both Pertamina and the joint venture. Discussions are currently under way regarding the financing of the seventh train, dock and other support facilities. The construction of the seventh train for an estimated cost of approximately $975 million is expected to begin in 1995.
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.
LNG is 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 Korea Gas Corporation ("KGC") signed in 1983 and 1991 (the "Korean Carryover" and "Korea II" contracts, respectively) and will be sold 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 1994, Pertamina negotiated extensions of the LNG contracts originally signed in 1973 and 1981, and also reached preliminary agreements for new proposed long-term LNG sales contracts with CPC and KGC. The 1973 contract will be extended for an additional period of ten years beyond 1999, and the 1981 contract will be extended for an additional period of five years beyond 2003. The proposed CPC and KGC long-term contracts will be in effect from 1998 until 2017. While memoranda have been signed by Pertamina and the buyers, final agreements for the extensions and the new long-term sales contracts are primarily conditional upon concluding LNG transportation arrangements and, with respect to the new long-term sales contracts,
certification of uncommitted reserves. Because the 1973 and 1981 contracts, as extended, will require the sale of quantities of LNG previously supplied by an LNG facility other than the Bontang plant, the capacity of the Bontang plant must be increased through the construction of a seventh train, which Pertamina agreed in 1994 to construct. Construction of the seventh train is expected to begin in 1995, and is currently scheduled for completion in 1998. In addition, preliminary studies are currently being conducted by Pertamina, the joint venture and the other production sharing contract groups regarding the planning, development, financing and construction of an eighth train, which could come on stream early in 2000, to primarily support the proposed CPC and KGC long-term contracts.
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 proposed 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 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 contracts has declined over time since the initial 1973 contract, when the joint venture was virtually the only supplier to the Bontang plant, to the present when there are several other major production sharing contractors supplying gas to the Bontang plant and sharing in the allocation of volumes. Pertamina has preliminarily set the participation of the joint venture in the 1973 contract extension at 22% based upon the joint venture's uncommitted reserves as of May 31, 1994, which percentage is less than the joint venture's participation in existing LNG contracts. This preliminary participation percentage is subject to final calculations by Pertamina, which should be concluded in 1995. Pertamina has not yet allocated the natural gas supply obligation in support of the extension of the 1981 contract or the proposed new CPC and KGC long-term contracts among the joint venture and the other production sharing contractors supplying natural gas to the Bontang plant; however, the amount of natural gas that the joint venture will supply to Pertamina in support of the 1981 contract extension and the proposed new sales contracts will be less than the amount of natural gas that the joint venture currently supplies in support of other existing LNG contracts, and the joint venture's participation may be less than 22%. A final determination regarding the joint venture's participation percentage for the 1981 extension and the proposed CPC and KGC long-term contracts is not expected before 1996. 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 proposed 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, Osaka, Korean Carryover, Korea II and MCGC contracts (together with the proposed new CPC and KGC contracts, the "long-term contracts") contain or will 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, 1994, under all of the contracts described in the table below (excluding any quantities called for by the extensions of the 1973 and 1981 contracts and the proposed new CPC and KGC long-term contracts), the long-term contracts and the short-term contracts represent approximately 95% and 5%, respectively, of such deliveries.
The following table sets forth information regarding the Bontang LNG plant's share of LNG sales contracts at December 31, 1994:
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(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. For the extension of the 1973 contract, 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 preliminarily set the joint venture's participation percentage at 22% based upon the joint venture's uncommitted natural gas reserves certified as of May 1994. This preliminary percentage is subject to final calculations by Pertamina. The Company anticipates a final determination of the joint venture's participation during 1995, which the Company does not expect to vary materially from 22%. For sales contracts not covered by this preliminary determination or by prior determinations, including the extension of the 1981 contract and the proposed new CPC and KGC long-term contracts, 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 may be less than 22%.
(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.
(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 applicable, and for recovering exploration, development and production costs and profit sharing between the joint venture and Pertamina.
(d) The joint venture has a 97.9% and 27.2% interest in 454 and 447 remaining TBtus, respectively, of the total 901 TBtus remaining to be sold under this contract. Under the extension of the 1973 contract, the joint venture is expected to have a 22% interest in sales of an additional 4,393 TBtus.
(e) The joint venture has a 66.4% and 29.6% interest in 1,394 and 157 remaining TBtus, respectively, of the total 1,551 TBtus remaining to be sold under this contract. The extension of the 1981 contract provides for the sale of an additional 925 TBtus. The joint venture's participation percentage in this extension, which may be less than 22%, will not be determined by Pertamina before 1996. (Notes continued on following page)
(f) The proposed new long-term sales contracts with CPC and KGC provide for the sale of 1,812 TBtus and 659 TBtus, respectively. Such new sales volumes are in addition to the 1,248 TBtus, 1,001 TBtus and 173 TBtus, respectively, remaining to be sold under the existing long-term contracts with CPC and KGC. Sales of LNG under the proposed new contracts will commence in 1998 and continue until 2017. The joint venture's participation percentage in these proposed contracts, which may be less than 22%, will not be determined by Pertamina before 1996.
(g) Memoranda of Agreement have been executed between Pertamina and the buyers for the sale of these quantities. The joint venture's preliminary participation percentage is 22%, as it falls within the time periods covered by Pertamina's preliminary determination discussed in footnote(a) above.
In general, the processing costs 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, CPC and MCGC 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, Korean Carryover and Korea II 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 other production sharing contractors.
At December 31, 1994, the average LNG price under all contracts supplied from the Bontang plant was $2.51 per MMBtu, or $2.77 per Mcf. Prices under the contracts are subject to monthly adjustments. As of December 31, 1994, January 31, 1995, and February 28, 1995, the average price for the group of crude oils used to determine the price of LNG was $16.17, $17.01 and $17.85 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 facility at the Bontang plant under seven contracts with Japanese purchasers, each of which is for a ten-year term. These LPG contracts, as amended, provide for delivery of an aggregate of approximately 1,950,000 metric tons of LPG (14.4 MMboe) per year, of which an aggregate of up to 800,000 metric tons of LPG (5.9 MMboe) per year will be from the Bontang plant. The balance of the LPG is to be supplied by the Arun plant, a plant to which the joint venture supplies no gas. The joint venture has 29.6% and 27.2% participations and a preliminary 22% participation 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 expects to have approximately a 22% 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 and dock facilities at the Bontang plant.
U.K. North Sea
The Company's principal U.K. North Sea properties include interests in the Piper, Claymore, Scapa, Saltire and Chanter oil fields, the Sean gas fields and the undeveloped 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
began in late 1976 and late 1977, respectively. After being shut down since July 1988 following a platform explosion, production in the Piper field commenced in February 1993 from a new fixed platform ("Piper B"). The proved reserves (net) as of December 31, 1994, contained in the Piper and Claymore fields are 23 MMboe and 23 MMboe, respectively, including an upward revision for the Piper field of approximately 9 MMboe recorded in the first quarter of 1994. Average daily production of oil and liquids (net to the Company) for 1994 from the Piper and Claymore fields was 15 MBbls and 8 MBbls, respectively. Average daily production rates for 1994 for the Piper and Claymore blocks were affected by a suspension of production from May to mid-June due to a natural gas leak. Production declines from the Piper and Claymore blocks are expected to begin in 1997.
In late 1992, a contract was awarded for the engineering, procurement and construction of a new platform to provide personnel accommodation facilities for the Claymore field. The new facilities will replace existing accommodations on the Claymore A production platform and the floating unit moored alongside. The installation is scheduled for completion in mid-1995. The Company's share of the cost of this new platform is currently estimated to be approximately $40 million through completion of the project. The Company spent approximately $12 million in 1994 on the platform and anticipates that it will spend approximately $11 million during 1995. These expenditures are 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 Company currently sells, at prevailing market prices, its crude oil production from the U.K. sector of the North Sea F.O.B. Flotta terminal to B.P. Oil International Limited and Elf Trading, two major international oil and gas companies, under contracts with a term of one year. The Company anticipates that based on current demand it will be able to sell its share of crude oil production from the U.K. sector of the North Sea.
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, such as the Scapa, Saltire and Chanter fields described below, by exempting all or part of their production from PRT. 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. See Item 7 -- Management's Discussion and Analysis of Financial Condition and Results of Operations.
Saltire Field. The Company has a 20% working and revenue interest in the Saltire field, which was discovered by the joint venture in 1988. This field is referred to as an edge oil field because it has a separate field designation, incurs little or no PRT, has no government royalty interest burden and is developed as a satellite from an existing platform. The Company developed Saltire using a fixed platform connected to the Piper B platform. Net expenditures by the Company for the Saltire development were approximately $180 million through December 31, 1994, inclusive of $5 million incurred during 1994. The Saltire platform was completed and production began in May 1993. Average daily production (net to the Company) for 1994 was 10 MBbls of oil and liquids. Proved reserves (net) at December 31, 1994, for Saltire were 13 MMboe.
Chanter Field. In July 1991, the U.K. Department of Energy approved the development of the Chanter field, which is also an edge oil field located approximately 120 miles northeast of Aberdeen on U.K. Block 15/17 (Piper) in the North Sea. The Chanter field was developed as a subsea satellite to the Piper B platform and utilized the existing pipeline system leading to the Flotta terminal in the Orkney Islands. The Company has a 20% working and revenue interest in the Chanter field. The field comprises two reservoirs, one oil and the other natural gas and condensate. Production from the Chanter field began in May 1993. Average daily production (net to the Company) for 1994 was 1 MBbls of oil and liquids. The proved reserves (net) contained in the field are 2 MMboe as of December 31, 1994.
Scapa Field. The Scapa oil 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. Scapa is
not subject to a government royalty interest, and it is anticipated that only small amounts of PRT will be paid on production from this edge oil field. Oil production from the Claymore and Scapa fields is transferred 135 miles via the joint venture's pipeline to the Flotta terminal. Average daily production (net to the Company) for 1994 was 5 MBbls of oil and liquids. Proved reserves (net) at December 31, 1994, for the Scapa field were 6 MMboe of oil.
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 and South Sean fields and the recently discovered East Sean field. Production from the East Sean field began in November 1994. The proved reserves (net) as of December 31, 1994, contained in the Sean fields were 24 MMboe, including 3 MMboe attributable to the East Sean field. The Company believes that the Sean properties have potential for additional gas reserves and production. The Company expects to participate in one or more exploratory wells to test structures adjacent to the existing Sean gas fields during 1995.
The Sean platforms, which currently serve the North and South Sean fields and the East Sean field, made their first deliveries in December 1986. Under the terms of a gas sales contract terminating in 2011 with British Gas plc, 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 British Gas plc. 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 1994 was $3.16 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 1994 totaled $32 million (net to the Company), and the revenue for the volume of gas taken on 29 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.
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 British Gas plc. The Company's share of gas from the East Sean field, which will produce year-round, is sold to Alliance Gas Limited under a short-term contract. Sales under this contract commenced in November 1994. Production from the East Sean field is not subject to PRT.
Britannia Field. In November 1994, the Company acquired a 9.42% unit interest in the undeveloped Britannia natural gas and condensate field in the U.K. North Sea from Fina Exploration Limited and Fina Petroleum Development Limited, subsidiaries of Petrofina SA. The purchase price was approximately $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, with an estimated $47 million budgeted for 1995 for drilling activities and initial platform fabrication and facilities work. The Britannia field will be 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 Oil Marine plc. As a result of the acquisition, the Company recorded, as of December 31, 1994, an additional 38 MMboe of proved undeveloped reserves to its year-end oil and gas reserves. 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. For additional information, see Item 7 -- Management's Discussion and Analysis of Financial Condition and Results of Operation.
Other Information. Payment to the Company with respect to oil production from the Piper, Claymore, Saltire, Chanter and Scapa fields is made in U.S. dollars, and payments under the Sean gas sales agreements with British Gas plc 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.
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 Badin concessions.
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 Government of Pakistan. 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 to be granted by the Government of Pakistan. Production from the 1992 concession is expected to begin 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 January 1992 under the 1992 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 Company will act as operator and will bear 38% of the costs of exploration, including 12.5% attributable to the Pakistan government. 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. Under the 1995 concession, the Company will explore for and develop oil and gas on the approximately 1.7 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 Government of Pakistan elects to exercise its option to increase its working interest in such discovery to 25%.
The Government of Pakistan 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, 1994, for the Company's interest in the Badin area were 4 MMBbls of oil and 98 Bcf of gas. The joint venture under the 1977 concession produced approximately 33% of Pakistan's total domestic oil output and 10% of the country's gas production in 1994. Average daily production (net to the Company) during 1994 was 5 MBbls of oil and 43 MMcf of gas. Oil production and drilling activities in 1994 were hindered by an unusually heavy monsoon season. The Company's share of the oil produced from the 1977 concession, and the 1992 concession when it is brought on stream, is sold for both Pakistan domestic 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 1994, the Company supplied 1 MMBbls 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. The Company expects that the natural gas produced from the 1992 concession area will be sold to
SSGC under a contract with terms similar to the SSGC contract covering production from the 1977 concession.
During 1994, the Company drilled six exploratory wells in the Badin concessions, two of which were discoveries. The discoveries included one gas field and one oil and gas field. During 1995, the Company plans to drill up to 15 exploration wells and three development wells in the Badin concessions.
Eastern Sindh Concession
In December 1994, the Government of Pakistan granted the Company a petroleum exploration license for the Eastern Sindh block in the Sindh Province of southeastern Pakistan. The Company will act as operator of the license area, which covers approximately 1.8 million acres, and holds a 70% working interest in the license, subject to reduction if the Pakistan government elects to participate upon discovery of commercial production. The exploration license will continue for a two-year period, which may be extended for another year upon commitment to drill an exploration well in the license area. The commencement of exploration activities is pending the negotiation with the Government of Pakistan of a concession agreement covering the license area.
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 $33 million for exploration wells in the Company's producing areas in the U.K. North Sea, Indonesia and Pakistan. The Company has also budgeted a total of $41 million for exploration activities during 1995 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 considering the possibility of investing in small power generation projects in Pakistan and Indonesia.
Argentina. The Company serves as operator and has a 50% working interest in a 4.4 million-acre offshore tract, known as the Cuenca Colorado Marina-1 ("CCM-1"), located in the South Atlantic Ocean about 310 miles south of Buenos Aires. In 1993, the Company's three-year risk service contract was converted into an exploration permit pursuant to an agreement with the Government of Argentina. The exploration permit provides the Company with the option to extend the term of the agreement until 1999 by electing to drill four wells at varying intervals during that period. An additional four-year extension is possible if the Company elects to drill one well for each year of the extension. During 1994, the joint venture drilled the first well on the CCM-1 block. The well identified oil-generating source rock, but did not discover commercial quantities of oil or gas. In January 1995, the Company acquired additional seismic data on the CCM-1 block. The venture plans to drill two additional wells on the CCM-1 block in 1995.
Vietnam. In 1994, the Company acquired a 25% working interest in an oil and gas production sharing contract offshore the southern coast of Vietnam. The 628,000-acre block is located in the South Con Son Basin in the South China Sea. The joint venture, operated by LASMO Vietnam Limited, drilled its initial exploratory well on the block in 1994. The well did not identify commercial quantities of oil and gas, but provided important data for use in locating future wells. The joint venture currently expects to drill two additional wells in 1995. The production sharing contract with the Government of Vietnam provides the joint venture with the right to conduct exploration activities through 1997 and grants the venture the right to produce any oil and natural gas discovered through 2017.
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 will act as operator and will bear 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. During 1994, the Company acquired additional seismic data. The Company currently plans to drill a well in 1995.
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, operated by the Company, has an initial three-year term expiring in 1996, with an optional two-year extension. The Company plans to drill a well in the first half of 1995.
Ireland. In early 1995, the Company entered into an agreement to acquire a 25% working and revenue interest in five and one-half offshore blocks encompassing approximately 345,000 acres in St. George's Channel offshore Ireland from Marathon Petroleum Ireland, Ltd. and Marathon Petroleum Hibernia, Ltd., wholly owned subsidiaries of Marathon Oil Company (collectively, "Marathon"). The Company's acquisition of an interest in the blocks is subject to approval by the Irish government. The exploration licenses, along with an additional exclusive licensing option, were awarded by the Irish government during 1993 and 1994. The operator for the consortium is Marathon. An initial exploratory well is planned for the second quarter of 1995.
In 1994, the Company also acquired a 30% working and revenue interest in a joint venture that was awarded 11 blocks offshore Ireland. The blocks cover approximately 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 (U.K.) Ltd. ("Statoil"), was granted the right to explore for oil and natural gas for a 16-year period. During the initial four-year term of the exploration license, the 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, the joint venture will determine whether the geology warrants drilling any wells and continuing the license.
The Company and its co-venturers, including Statoil, have applications pending with the Irish government for several blocks offshore southwest Ireland in the Porcupine Basin.
Italy. The Company has entered into agreements to acquire interests in three onshore exploration permits covering approximately 217,000 acres in the Basilicata Region in southern Italy, subject to approval by the Italian government. The Company will serve as operator of and will hold a 42% working interest in the Serra Corneta permit. The Company will also hold 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 are planned for 1995. The Company has also filed applications with the Italian government for additional exploration permits covering areas adjacent to the Serra Corneta and Tempa dei Mercanti permit areas.
Eastern Indonesian. In Eastern Indonesia, the Company has a 60% working interest and is operator for a group that in May 1991 was granted three new production sharing contract areas for an initial term ending in 1997 (subject to extension if certain work programs are carried out), covering approximately 13 million acres (gross) located in the Maluku (Moluccas) Island group in the Banda Sea. During 1994, the Company increased its interest from 33.33% by assuming the interest of another participant. The Company completed a program to acquire seismic and geological data for these three areas during 1992 and 1993. In February 1995, the Company entered into a new production sharing contract covering an area immediately adjacent to that covered by the three other production sharing contracts. The Company also is the operator and has a 60% working interest in the new production sharing contract. The Company currently plans to drill a well in the area covered by these production sharing contracts in 1995.
Papua New Guinea. The Company serves as operator and has an 80% working interest in a petroleum prospecting license located onshore and offshore Papua New Guinea. The license expires in 1996, subject to extension. The initial well drilled in the prospecting license area during 1993 was unsuccessful. In 1995, the Company plans to evaluate additional information to determine its future exploration strategy.
ALASKA
The Company also pursues exploration projects in Alaska. At year-end 1994, the Company held acreage primarily in the Colville Delta, Cook Inlet and offshore the Beaufort Sea in Alaska.
Colville Delta. During 1994, the Company participated in the drilling and testing of two wells in the Western Colville area. The results of these two wells were not released. The wells drilled in 1994 followed the drilling of several wells in prior years in the general Colville Delta area, certain of which wells encountered quantities of oil. During 1994, the Company entered into an agreement to increase its working interest from an average of 13.2% to 22% in the Western Colville area by agreeing to bear a disproportionate share of the costs incurred in drilling two wells scheduled to be drilled in the first quarter of 1995 to evaluate commerciality. 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, 1995, the Company exercised its option and leased approximately 14,500 acres and has a remaining option to lease approximately 75,000 acres, which reduces in stages until the expiration of the agreement on November 1, 1996. During 1994, the Company interpreted geophysical data acquired pursuant to the terms of the exploration agreement and plans to acquire additional seismic data during 1995. Pending favorable results from the seismic studies, drilling could commence in 1996 or 1997. Also in 1994, the Company acquired leases on 17 blocks onshore and offshore the Kenai Peninsula pursuant to a lease sale held by the State of Alaska; however, the holding of the lease sale is being challenged in the Alaskan state courts. The Company has a 100% working interest in the leases, subject to CIRI's election to acquire a 20% working interest in certain of the leases under the terms of the exploration agreement.
Kuvlum. In 1994, the Company assumed the other participants' working interest in the Kuvlum federal exploratory oil and gas unit in the Beaufort Sea offshore Northern Alaska in order to maintain the federal leases included in the unit for further economic and technical analysis. Two wells drilled during 1993 did not confirm the commerciality of the Kuvlum unit as a stand-alone development, and the Company wrote off its $25 million investment in the unit. See Item 7 -- Management's Discussion and Analysis of Financial Condition and Results of Operations.
PETROCHEMICAL BUSINESS
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. In 1994 and 1993, the Company's net ethylene sales were 436 million pounds and 451 million pounds, respectively, and its net propylene sales were 32 million pounds and 27 million pounds, respectively. The Company sells its share of the ethylene produced by the plant to several major customers for the manufacture of plastics used in various consumer products. The sales price of ethylene averaged $0.20 per pound in 1994 and $0.16 per pound in 1993. Sales of propylene, used in the manufacture of various products such as building materials, clothing and tires, averaged $0.14 per pound and $0.09 per pound in 1994 and 1993, respectively.
With the start-up of the twelfth furnace at the Geismar plant during February 1995, the facility 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. During 1994, the plant underwent a regularly scheduled maintenance turnaround and therefore operated at approximately 88% of its rated capacity. During the turnaround, the Company supplied its customers with ethylene and propylene from storage.
During 1994, the average margin on a pound of ethylene increased from approximately $0.01 per pound in the first quarter of 1994 to $0.12 per pound in December. The Company's ethylene margin is primarily affected by the cost of feedstock (natural gas liquids) and the price received for the ethylene. Low natural gas prices in the United States and higher ethylene prices, resulting from tight supplies of ethylene and increased demand, caused significantly higher margins during the second half of 1994 than in the first half of 1994 and the previous year. 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 1994. The Company plans to spend $5 million (net to the Company) in capital expenditures for the petrochemical business during 1995. Expenditures during 1994 and 1995 include costs associated with the installation of the twelfth furnace.
Storage and Transportation. In addition to the Geismar plant, the Company owns and operates a 188-mile ethane gathering pipeline system, which transports feedstock to its ethylene plant from several major suppliers, including the Company's natural gas liquids fractionation plant in Rayne, Louisiana. Production from the Rayne plant during 1994 was level with 1993 production. The Company also operates an underground storage terminal and a 50-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 BUSINESS 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. 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 regulations have had an increasing impact upon the Company's operations. Environmental expenditures for 1994 included capital outlays for existing facilities, as well as air and water quality projects, and were made predominantly in the petrochemical business area. Such expenditures for 1994 were not material, nor are they expected to be material during 1995.
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 United States 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 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" into the environment. Under these laws, the Company could be required in the future, with respect to future Alaskan operations or prior U.S. activities, 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 respecting 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 United Kingdom are subject to the Prevention of Oil Pollution Act, the Environmental Protection Act and related statutes and orders, as well as
certain European Community 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-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 other 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 28, 1995, the Company had approximately 1,000 employees. The Company believes that its relations with its employees are good.
ITEM 2.
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.
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.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
None.
PART II
ITEM 5.
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 28, 1995, there were approximately 87,648,932 shares of Common Stock outstanding held by approximately 330 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 on the New York Stock Exchange for 1993 and 1994:
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 28, 1995, was $19 1/4.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA.
The financial data as of and for the years ended December 31, 1990 through 1994 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.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
RESULTS OF OPERATIONS
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 primarily due to lower prices for crude oil and natural gas.
Average prices received and volumes sold by the Company's major operations during 1994 and 1993, respectively, were as follows.
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.
1993 Compared with 1992. Net income for the year ended December 31, 1993, was $27 million, or $.31 per share, as compared to net income of $14 million, or a loss of $.26 per share, reported for the year
ended December 31, 1992. Included in 1993 results are certain significant items related to the U.K. North Sea's Piper field write-down, the benefit of a U.K. tax law change, the write-off of the Kuvlum prospect in Alaska and a charge for the cumulative effect of adopting a new accounting standard for postemployment benefits. Excluding these items, net income for the year ended December 31, 1993, was $54 million, or $.61 per share. The prior period's results include a $76 million charge for the cumulative effect of adopting two new accounting standards effective January 1, 1992. The prior period's results also include an extraordinary charge of $20 million for the early redemption of certain of the Company's debt in early 1992. Excluding these items, net income for the year ended December 31, 1992, was $109 million, or $.86 per share. The 1993 earnings were negatively impacted by lower oil and Indonesian LNG prices and decreased interest income on refunds of prior years' Petroleum Revenue Tax ("PRT"). The 1993 results benefitted from the elimination of preferred stock dividends and higher worldwide oil volumes.
Sales and operating revenues for 1993 were $682 million, an increase from $669 million for 1992. International revenues totaled $537 million as compared to $500 million in 1992. In the U.K., sales increased by $52 million primarily due to increased production from the Piper and Saltire fields, partially offset by lower prices. In Indonesia, sales decreased by $19 million due to lower LNG and oil prices, partially offset by increased LNG volumes. In Pakistan, sales increased $6 million due primarily to higher natural gas prices and higher oil and gas volumes. The average sales price for U.K. crude oil decreased from $18.47 to $15.10 per barrel. The average sales price received for Indonesia LNG decreased from $3.41 per Mcf to $3.17 per Mcf. The average sales price received for Pakistan natural gas increased from $1.09 per Mcf to $1.26 per Mcf.
The Company's petrochemical operation's operating profit increased $4 million from the prior year due to lower costs. The average sales price of ethylene ($.16 per pound) was consistent with the prior year.
Interest income and other revenues in the U.K. decreased by $21 million, primarily due to lower refunds of prior years' PRT associated with the development costs of the Piper field. Domestic interest income and other revenues were $5 million below the prior year primarily due to a lower level of interest bearing cash investments held during the current year.
Exploration expenses increased by $27 million primarily due to the write-off of the Company's investment in the Kuvlum prospect in Alaska. Two exploratory wells drilled in the third quarter indicated that the prospect was not commercial as a stand-alone development.
Depreciation increased by $166 million during 1993 due to increased production in the North Sea and the $103 million pretax ($48 million after-tax) write-down of the Company's investment in the Piper field. (See Note 2 of Notes to Consolidated Financial Statements.)
The Company's taxes decreased from the prior period primarily due to a one-time reduction in deferred taxes as a result of a decrease in the PRT rate in the North Sea, which had a one-time favorable impact to net income of approximately $50 million.
Earnings per share of common stock were favorably impacted by the elimination of dividends on the preferred stock and accretion of discount on common stock warrants. Dividends on the Series B and C Preferred Stock decreased during the period by $30 million as a result of the redemption of this stock in September 1992. Similarly, accretion of discount on common stock warrants decreased in the current period by $5 million as a result of the redemption of the warrants in September 1992.
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.
FINANCIAL CONDITION AND LIQUIDITY
General. The Company's strategic focus is to build shareholder value through developing its core holdings, conducting an active exploration program, pursuing oil and gas acquisition opportunities and continuing to control costs. The Company's capital expenditures for 1995 are estimated to be $212 million, excluding capitalized interest, an increase from the previously budgeted $170 million for 1995, which is due primarily to the Britannia field development costs. Approximately one-third of the 1995 capital budget is allocated to fund the Company's expanded worldwide exploration program, which represents an 85% increase over exploration program funds expended in 1994. A total of $74 million is included in the Company's budget for exploration activities, including at least ten exploration wells in new venture areas in Alaska, Argentina, Eastern Indonesia, Ireland, Tunisia and Vietnam, and as many as 20 wells in ongoing exploration programs in the Company's producing areas in the U.K. North Sea, Indonesia and Pakistan. The budget also includes approximately $132 million for oil and gas development programs in the Company's producing areas, including $47 million for the initial development of the Britannia field. The Company has also budgeted approximately $5 million for its petrochemical interests in the United States. In 1995, the Company intends to evaluate acquisition opportunities of developed and undeveloped oil and gas reserves and to add to its production base in the near-term. Acquisition costs are not included in the estimated capital expenditures for 1995, but the Company believes that its financial strength and available credit give it the financial resources to make acquisitions.
As a result of the completion of large development projects for the Piper and Saltire fields in the U.K. North Sea and a continuation of the growing demand for Indonesian LNG, the Company experienced record levels of production from its international operations during 1994, which increased 16% from 1993 levels. The Company's objective is for production in 1995 to exceed 1994 levels.
In developing its business plan for 1995, the Company expects that it will continue to have excess cash flow available after capital expenditures, required debt service and normal dividends. The business plan is based upon numerous assumptions made by management including assumptions as to the volume of oil and gas the Company will produce from its properties and the prices received for such production. Pricing for the Company's business plan is based on the assumption that the spot price of West Texas intermediate will average $18.75 per barrel for 1995. Approximately 90% of the Company's oil and gas revenues are indexed to world crude oil prices.
Although management believes that the assumptions used at the time in formulating the business plan and the resultant estimate of excess cash flow were reasonable in light of world energy, financial and economic conditions, and the Company's cash requirements, such conditions could change materially, and actual results of operations, cash flows and use of cash by the Company through 1995 may vary materially from those included in the business plan.
Cash flow from operations. Net cash provided by operating activities was $215 million in 1994, an increase of $24 million from the same period in the prior year. The increase was primarily the result of increased U.K. oil and Indonesian LNG sales volumes and improved ethylene margins, partially offset by lower oil and gas prices.
During the last six months of 1994, ethylene margins improved significantly from the first six months of 1994. By December 1994, margins had risen to approximately 12 cents per pound, up from about 1 cent at the beginning of the year. The Company's ethylene margins averaged 6 cents per pound for the full year 1994, and the Company's petrochemical business posted 1994 operating profit of $24 million. The Company has utilized an average 8 cents per pound ethylene margin for the full year 1995 in its business plan for 1995. The Company estimates that a margin improvement of an average one cent per pound for an entire year at full capacity production can provide approximately an additional $5 million in operating profit and net income on an annualized basis for the petrochemical business of the Company. Ethylene margins have averaged approximately 15 cents per pound in the first two months of 1995. The Company cannot predict the duration of the recent favorable trends in the ethylene business. The prices the Company receives for its ethylene are sensitive to many factors beyond the control of the Company, such as worldwide and U.S. demand for
petrochemicals, inventory levels, feedstock costs and availability, plant utilization rates, plant operations and costs and competitive capacity expansion.
Capital resources. Capital expenditures for 1994, exclusive of the Britannia acquisition, were $131 million, a decrease from the prior year's expenditures of $192 million primarily as a result of the completion of the large development projects in the U.K. North Sea. During 1993, Piper redevelopment costs were $22 million and Saltire development costs were $23 million. In 1994, the Company spent $45 million in Indonesia, primarily on exploration and development drilling. In 1994, 1993 and 1992, total Company capital costs incurred, including capitalized interest, totaled $309 million (including $159 million related to the Britannia acquisition), $218 million and $325 million, respectively.
On November 4, 1994, the Company acquired from Fina Exploration Limited and Fina Petroleum Development Limited, subsidiaries of Petrofina SA (collectively, "Fina"), a 9.42% unit interest in the Britannia field, the largest undeveloped natural gas and condensate field in the U.K. North Sea, for 83.8 million pounds sterling (approximately $133 million). In December 1994, the U.K.'s Department of Trade and Industry ("DTI") approved the development program for the Britannia field. As a result of the DTI approval of the development program, the Company made a second agreed upon payment to Fina for 16.8 million pounds sterling (approximately $26 million) in December. At year-end 1994, the Company recorded 38 million boe as proved undeveloped reserves associated with the acquisition. The Company expects to record additional proved reserves from the Britannia field in the future based on the field's development results and its production history. The Company increased oil and gas properties and equipment by $219 million, resulting from the purchase price of $159 million, financed through debt, and an offset to deferred income taxes payable of $60 million. The Company's share of total development costs for Britannia, at current exchange rates, is estimated to be approximately $200 million, with $47 million budgeted for 1995 for drilling activities and initial platform fabrication and facilities work. Initial production from Britannia is expected in late 1998. The Britannia field will be operated by Britannia Operator Limited, a joint venture between Conoco (U.K.) Ltd. and Chevron U.K. Ltd. The Company has contracted to sell a substantial portion of its share of gas from Britannia under long-term sales agreements with several large gas purchasers in the U.K. Revenues from the Britannia field will be subject to a U.K. corporate tax but not to U.K. government royalty or PRT.
Financing activities. During 1994, the Company replaced its $650 million unsecured revolving credit facility with three unsecured credit facilities (the "Credit Facilities"). One of the Credit Facilities is a $100 million unsecured credit agreement with NationsBank of Texas, N.A. ("NationsBank"), as agent, Bank of America National Trust and Savings Association ("Bank of America") and Union Bank of Switzerland, Houston Agency ("UBS"), as co-agents. This Credit Facility is a revolver that provides for conversion of amounts outstanding on September 15, 1995 to a one-year term loan maturing September 15, 1996. The Company's other two Credit Facilities are with NationsBank, as agent, Bank of America and UBS, as co-agents, and certain other banks. One of these Credit Facilities is a $350 million revolver that reduces quarterly by $25 million beginning July 31, 1997 and has a final maturity of April 30, 1998. The other Credit Facility is a $200 million revolver that provides for conversion of outstanding amounts on April 30, 1995 to a one-year term loan maturing April 30, 1996. The Company is pursuing amendments to extend the maturities on the latter two Credit Facilities. Loans under the $350 million revolver may be made in both pounds sterling and U.S. dollars at the option of the Company. 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. In addition, the $350 million revolver allows the Company to obtain up to $200 million of availability thereunder in U.S. dollar loans that bear interest at a rate determined in a competitive bid process. Borrowings under the Credit Facilities are guaranteed by certain subsidiaries of the Company that also guarantee the Company's senior notes due 1999. The Credit Facilities contain restrictive covenants, including limitations on incurrence of additional indebtedness, asset sales and mergers or consolidations. The Credit Facilities restrict the amount of total indebtedness incurred by the Company and the restricted subsidiaries referred to in the Credit Facilities, which include the guarantors and certain other subsidiaries ("Restricted Subsidiaries"), to $750 million of senior indebtedness (including the senior notes due 1999 and amounts drawn under the Credit Facilities) and $100 million of subordinated indebtedness.
Debt of unrestricted subsidiaries and nonrecourse debt on certain assets of the Company and its subsidiaries are not limited under the Credit Facilities, subject to certain conditions. The covenants also require maintenance of a certain level of stockholders' equity. 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 the other covenants in the Credit Facilities. Based on current conditions, the Company expects to pay dividends without restriction under the Credit Facilities. At December 31, 1994, $326 million was outstanding under the Credit Facilities bearing interest at a weighted average rate of 6.54% per annum, and approximately $220 million was available for additional borrowings under such existing Credit Facilities. At February 28, 1995, $302 million was outstanding under the Credit Facilities.
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. At December 31, 1994, $106 million was outstanding under these lines. These amounts outstanding bear interest at a weighted average rate of 6.46% per annum and are included in the total indebtedness restriction under the Company's Credit Facilities and reduce amounts available under the Company's Credit Facilities. At February 28, 1995, $111 million was outstanding under these lines of credit.
Funding for the acquisition of the Britannia field was through the Company's Credit Facilities and its uncommitted and unsecured lines of credit. The Company's indirect subsidiary, Union Texas Britannia Limited ("UTBL"), which is a wholly owned subsidiary of Union Texas Petroleum Limited ("UTPL"), has received a commitment, subject to negotiation of definitive agreements, from Chemical Bank, NationsBank N.A. (Carolinas) and National Westminster Bank plc for a 150 million pounds sterling secured financing. The financing will be 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 to refinance acquisition costs. Except for certain support by UTPL related to any potential cost overruns in excess of the facility amount (limited to 30 million pounds sterling), 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 will have a final maturity in September 2005. The borrowings by UTBL, an unrestricted subsidiary, would not be included in the total indebtedness under the Company's Credit Facilities and will not reduce amounts available under the Credit Facilities.
The Company has an effective shelf registration statement on file with the Commission covering up to $200 million of its debt securities, which the Company may elect to offer from time to time and on such terms as the Company deems appropriate in the form of senior debt securities, which may be guaranteed by certain of the Company's subsidiaries, or subordinated debt securities. Amounts of debt securities that may be offered pursuant to the shelf registration statement will reduce amounts available under the Credit Facilities. The Company believes the shelf registration provides additional financing flexibility to meet future funding requirements and to take advantage of potentially attractive capital market conditions. No securities have yet been issued. In addition, at the 1995 Annual Meeting of Stockholders to be held May 10, 1995, the Company will seek stockholder approval to authorize a new class of 15,000,000 shares of preferred stock. The new preferred stock will provide the Company additional flexibility to issue from time to time this form of equity based on current market conditions.
On January 4, 1994, Unimar, an equity partnership, redeemed the 8.25% convertible subordinated guaranteed debentures which were due in 1995. The Company's share of the debt redemption was approximately $18 million and was funded by additional short-term borrowings.
As of December 31, 1994, the Company's scheduled maturities of long-term debt outstanding for the five-year period of 1995 through 1999 are approximately $2 million, $2 million, $28 million, $300 million and $100 million, respectively. The Company believes that it will have sufficient sources of funds to satisfy these scheduled maturities. The Company is considering refinancing alternatives in order to extend its 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 1994.
On April 27, 1994, the Board authorized the repurchase of up to 2,000,000 shares of common stock to be used for general corporate purposes, including fulfilling employee benefit program obligations. During 1994, the Company repurchased 307,500 shares of common stock at a cost of $5.6 million, a portion of which shares were used to fund employee savings and benefit plan obligations. At December 31, 1994, 221,565 shares of common stock were held, at cost, as treasury shares.
Financial Condition. During January 1993, the Company entered into an agreement to terminate a portion of its Houston office building lease and accordingly made a $35 million payment to the lessor in consideration of such agreement in March 1993 for which an accrual had been made in 1992.
In each of the four quarters ended December 31, 1994, the Company declared and paid a dividend of approximately $4.3 million on its common stock. On January 12, 1995, the Company announced a dividend on its common stock of $.05 per share to stockholders of record as of January 31, 1995, which was paid on February 15, 1995.
Effective July 1, 1993, the British Parliament enacted changes in PRT that will have an overall positive impact on the Company's operations in the North Sea. The changes included reforms which reduced PRT on producing fields in the North Sea from 75% to 50% and which abolished PRT for all new fields not licensed for development on March 16, 1993. A substantial portion of the Company's production in the U.K. benefitted from such changes. Also enacted was the elimination of PRT deductions for most exploration and appraisal expenditures incurred on or after March 16, 1993, subject to limited transitional allowances through December 31, 1994.
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 of three months or less. At December 31, 1994, the Company had open contracts with a net value of 5 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 1995 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 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 Note 19 of Notes to Consolidated Financial Statements for information regarding the Company's estimated proved reserves and sales related to LNG.
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. 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. The Company's long-term strategy is to increase its production with reserve acquisitions and successful exploration and development activities. There can be no assurances that the Company will achieve such objectives. 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 19 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, foreign government approvals of lease, permit or similar applications and of exploration and production plans, political and economic instability, disputes between governments, 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.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
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, 1994 and 1993, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1994, 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 and its methods of accounting for income taxes and postretirement benefits other than pensions in 1992.
PRICE WATERHOUSE LLP
Houston, Texas January 25, 1995
UNION TEXAS PETROLEUM HOLDINGS, INC.
CONSOLIDATED BALANCE SHEET (DOLLARS IN THOUSANDS)
ASSETS
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*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.
UNION TEXAS PETROLEUM HOLDINGS, INC.
CONSOLIDATED STATEMENT OF OPERATIONS (DOLLARS IN THOUSANDS EXCEPT PER SHARE AMOUNTS)
The accompanying notes are an integral part of this financial statement.
UNION TEXAS PETROLEUM HOLDINGS, INC.
CONSOLIDATED STATEMENT OF CASH FLOWS (DOLLARS IN THOUSANDS)
The accompanying notes are an integral part of this financial statement.
UNION TEXAS PETROLEUM HOLDINGS, INC.
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY (DOLLARS IN THOUSANDS)
The accompanying notes are an integral part of this financial statement.
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 38% of the Company's issued and outstanding common stock.
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.
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 and 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.
Oil and gas assets are reviewed when they are fully placed into service to insure that capitalized costs of the asset do not exceed undiscounted future net pretax cash flows and are further reviewed annually on a country-by-country basis.
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 3 to 31 years.
Income taxes
In February 1992, the Financial Accounting Standards Board ("FASB") released Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes," which requires an asset and liability approach for financial accounting and reporting of income taxes. The Company adopted the Statement
UNION TEXAS PETROLEUM HOLDINGS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (DOLLARS IN THOUSANDS UNLESS OTHERWISE INDICATED)
effective January 1, 1992, by recording a cumulative charge to net income of $31 million representing the effect on prior years of adopting the Statement; otherwise, adoption of the standard did not materially impact 1992 results of operations.
Under this accounting standard, 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.
Postretirement health care benefits
In December 1990, the FASB released Statement of Financial Accounting Standards No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," which concluded that postretirement benefits represent a form of deferred compensation and that the cost and obligation should be recognized based on service. The Statement contains provisions that are similar to the FASB's approach to accounting for pension costs. The Company adopted the Statement effective January 1, 1992, by recording a cumulative charge to net income of approximately $45 million representing the effect on prior years of adopting the Statement; otherwise, adoption of the standard did not materially impact 1992 results of operations.
Postemployment benefits
In December 1992, the 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.
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 1994, 1993, and 1992 were ($178), $492, and ($4,318), respectively.
UNION TEXAS PETROLEUM HOLDINGS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (DOLLARS IN THOUSANDS UNLESS OTHERWISE INDICATED)
Foreign exchange contracts
The Company periodically enters into foreign exchange contracts as a hedge against fluctuations in foreign currency rates. These contracts hedge economic exposures. 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.
NOTE 2 -- PIPER FIELD WRITE-DOWN
It is the policy of the Company to review oil and gas assets when they are fully placed in service to insure that capitalized costs of the asset do not exceed undiscounted future net pretax cash flows. In the third quarter of 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 -- OTHER CHARGES, NET
The following pretax charges (credits) are reflected in the Company's Consolidated Statement of Operations as other charges, net for the year ended December 31, 1992:
In January 1992, the Company sold its wholly owned subsidiary, Unola de Argentina Ltd. ("Unola"), which held a minority interest in an onshore Argentine oil production service contract, for approximately $16 million and recorded a gain of $6 million. This sale did not include the Company's exploration acreage offshore Argentina.
During January 1993, the Company entered into an agreement to terminate a portion of its Houston office building lease and in March 1993 made a payment to the lessor of $35 million in consideration of such agreement.
UNION TEXAS PETROLEUM HOLDINGS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (DOLLARS IN THOUSANDS UNLESS OTHERWISE INDICATED)
NOTE 4 -- ACCOUNTS AND NOTES RECEIVABLE
At December 31, 1994 and 1993, accounts and notes receivable consisted of the following:
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 5 -- INVENTORIES
At December 31, 1994 and 1993, inventories consisted of the following:
Inventories valued at LIFO amounted to $1,822 at December 31, 1994 and $281 at December 31, 1993, which were below estimated replacement cost by $8,474 and $792, respectively.
NOTE 6 -- EQUITY INVESTMENT
At December 31, 1994 and 1993, an investment, accounted for using the equity method, consisted of the following:
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%. The Company's share of Unimar's nonrecourse debt of $18 million was redeemed on January 4, 1994.
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 is summarized as follows:
NOTE 7 -- PROPERTY, PLANT AND EQUIPMENT
At December 31, 1994 and 1993, property, plant and equipment consisted of the following:
In November 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 83.8 million pounds sterling (approximately $133 million). In December 1994, the U.K. Department of Trade and Industry ("DTI") approved the development program for the Britannia field. As a result of the DTI approval of the development program, the Company made a second agreed upon payment to Fina for 16.8 million pounds sterling (approximately $26 million) in December. Production from Britannia is planned to begin in late 1998. The Company increased oil and gas properties and equipment by $219 million, resulting from the purchase price of $159 million, financed through debt, and an offset to deferred income taxes payable of $60 million.
UNION TEXAS PETROLEUM HOLDINGS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (DOLLARS IN THOUSANDS UNLESS OTHERWISE INDICATED)
NOTE 8 -- DEBT
At December 31, 1994 and 1993, long-term debt consisted of the following:
Credit Facilities
During 1994, the Company replaced its $650 million unsecured revolving credit facility with three unsecured credit facilities (the "Credit Facilities"). One of the Credit Facilities is a $100 million unsecured credit agreement with NationsBank of Texas, N.A., as agent, Bank of America National Trust and Savings Association and Union Bank of Switzerland, Houston Agency, as co-agents. This Credit Facility is a revolver that provides for conversion of amounts outstanding on September 15, 1995 to a one-year term loan maturing September 15, 1996, if drawn. The Company's other two Credit Facilities are with NationsBank of Texas, N.A., as agent, Bank of America National Trust and Savings Association and Union Bank of Switzerland, Houston Agency, as co-agents, and certain other banks. One of these Credit Facilities is a $350 million revolver that reduces quarterly by $25 million beginning July 31, 1997 and has a final maturity of April 30, 1998. The other Credit Facility is a $200 million revolver that provides for conversion of outstanding amounts on April 30, 1995 to a one-year term loan maturing April 30, 1996. Borrowings are guaranteed by certain subsidiaries of the Company that also guarantee the Notes (see Note 20). The Credit Facilities contain restrictive covenants, including limitations on incurrence of additional indebtedness, asset sales and mergers or consolidations. The Credit Facilities restrict the amount of total indebtedness incurred by the Company and the restricted subsidiaries referred to in the Credit Facilities, which include the guarantors and certain other subsidiaries ("Restricted Subsidiaries"), to $750 million of senior indebtedness (including the Notes and amounts drawn under the Credit Facilities) and $100 million of subordinated indebtedness. Debt of unrestricted subsidiaries and nonrecourse debt on certain assets of the Company and its subsidiaries are not limited under the Credit Facilities, subject to certain conditions. The covenants also require maintenance of a certain level of stockholders' equity. Loans under the $350 million revolver may be made in both pounds sterling and U.S. dollars, at the option of the Company. 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. In addition, the $350 million revolver allows the Company to obtain up to $200 million of availability thereunder in U.S. dollar loans that bear interest at a rate determined in a competitive bid process. At December 31, 1994, outstanding borrowings bore interest at a weighted average of 6.54% 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 November 1992, the Company sold $100 million principal amount, at an initial offering price of 99.424%, of 8.25% Senior Notes due November 15, 1999 (the "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 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. The Notes
UNION TEXAS PETROLEUM HOLDINGS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (DOLLARS IN THOUSANDS UNLESS OTHERWISE INDICATED)
are guaranteed by the subsidiaries that are guarantors under the Credit Facilities (see Note 20). The 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 Notes.
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, 1994, such interest rate was 7.53%.
Short-term Debt
Uncommitted and unsecured lines of credit are established with several banks in both U.S. dollars and pounds sterling. At December 31, 1994, $106 million was outstanding under these lines, which bore interest at a weighted average rate of 6.46% per annum. These amounts are included in the total indebtedness restriction under the Company's Credit Facilities, thereby reducing amounts available under the Company's Credit Facilities.
Subordinated Debt
In February 1992, the Company redeemed all of its outstanding $100 million Senior Subordinated Reset Notes due November 1, 1993, at a redemption price of 103.125% together with accrued interest, and all of its outstanding $310 million 13% Subordinated Notes due July 1, 1995, at a redemption price of 104% together with accrued interest. The notes were redeemed by using existing cash balances. As a result, an extraordinary loss of $20 million was recorded representing the debt premium and the remaining unamortized issuance cost. The $100 million Senior Subordinated Floating Rate Notes due November 1, 1992 were repaid at maturity with borrowings under the Company's credit facility.
Interest capitalized for the years 1994, 1993 and 1992 was $18,774, $25,674 and $17,215, respectively.
Scheduled maturities of long-term debt outstanding during the five years 1995 through 1999 are $2,292, $2,292, $27,793, $300,000 and $100,000, respectively.
NOTE 9 -- INCOME TAXES
UNION TEXAS PETROLEUM HOLDINGS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (DOLLARS IN THOUSANDS UNLESS OTHERWISE INDICATED)
The principal items accounting for the difference in taxes on income computed at the United States statutory rate and as recorded are as follows:
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 the third quarter of 1993, 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:
NOTE 10 -- 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.
UNION TEXAS PETROLEUM HOLDINGS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (DOLLARS IN THOUSANDS UNLESS OTHERWISE INDICATED)
The Pension Plan has assets in excess of the accumulated benefit obligation. 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, 1994 and 1993:
Net periodic pension cost for 1994, 1993 and 1992 included the following components:
Settlement losses resulted from certain lump sum payments to employees who terminated from participation in the Supplemental Retirement Plans during the year. Net periodic pension expense decreased from 1992 due primarily to changes in actuarial assumptions and gain and loss experience.
The assumed average rate of return on plan assets was 8% in 1994, 1993 and 1992 for the plans. Measurement of the projected benefit obligation was based on an assumed discount rate of 8.5% and 7% in 1994, 7.5% and 7% in 1993 and 8% and 6.5% in 1992 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%, 5% and 5% for the Pension and Supplemental Retirement Plans in 1994, 1993 and 1992, respectively.
UNION TEXAS PETROLEUM HOLDINGS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (DOLLARS IN THOUSANDS UNLESS OTHERWISE INDICATED)
NOTE 11 -- 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:
Net postretirement benefit cost for 1994, 1993 and 1992 included the following components:
Measurement of the accumulated postretirement benefit obligation was based on an assumed discount rate of 8.5% for 1994, 7.5% for 1993, and 8% for 1992. For measurement purposes, a 12.75%, 13.5% and 14.25% annual rate of increase in the per capita cost of covered health care benefits for those age 65 and older were assumed for 1994, 1993 and 1992, 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, 1994 and 1993, by $1,451 and $1,479, 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, 1994, 1993 and 1992 by $176, $151 and $469, respectively.
UNION TEXAS PETROLEUM HOLDINGS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (DOLLARS IN THOUSANDS UNLESS OTHERWISE INDICATED)
NOTE 12 -- STOCK OPTIONS
Under the terms of the 1992 Stock Option Plan, the Company has 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 options with appreciation rights. At December 31, 1994, options outstanding with respect to 789,100 shares of common stock have appreciation rights attached.
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*298,700 shares granted in 1994 were granted with stock appreciation rights.
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, 1994, options outstanding with respect to 381,566 shares of common stock have appreciation rights attached.
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.
UNION TEXAS PETROLEUM HOLDINGS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (DOLLARS IN THOUSANDS UNLESS OTHERWISE INDICATED)
In connection with the stock acquisition by the KKR Partnerships, officers and key employees purchased common stock for approximately $3 million and obtained options, which are subject to the terms of the 1985 Plan, to acquire additional common stock for approximately $14 million at prices equivalent to that paid by the KKR Partnerships. In some instances, the appreciation rights could only be exercised with respect to 36% of the shares covered by each option.
NOTE 13 -- MAJOR CUSTOMERS
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. During 1992, the Company's Indonesian operations had sales to Chubu Electric, a Japanese utility, in the amount of $75,374 or 11% of total sales and operating revenues.
NOTE 14 -- SEGMENT FINANCIAL DATA
(Table continued on following page)
UNION TEXAS PETROLEUM HOLDINGS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (DOLLARS IN THOUSANDS UNLESS OTHERWISE INDICATED)
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(a) Petrochemicals operations and Other represent United States activities.
NOTE 15 -- 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, 1994, totaled $12 million. At December 31, 1994, the Company had open foreign exchange contracts with a net value of 5 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 1995 through 1999 are $8,200, $8,515, $8,326, $8,346 and $8,421, respectively.
Rental expense for the years 1994, 1993 and 1992 was $9,520, $8,339, and $8,528, respectively.
NOTE 16 -- 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.
UNION TEXAS PETROLEUM HOLDINGS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (DOLLARS IN THOUSANDS UNLESS OTHERWISE INDICATED)
NOTE 17 -- EARNINGS (LOSS) PER SHARE
Earnings (loss) per share of common stock are based upon the following:
Dividends on the Series B and C Preferred Stock were eliminated after September 1992 as a result of the redemption of this stock. Similarly, accretion of discount on the common stock warrants were eliminated after September 1992 as a result of the redemption of the warrants.
NOTE 18 -- SUPPLEMENTARY QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
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Source of Market Prices: New York Stock Exchange Composite Transactions Tape
(a) As discussed in Note 1, the Company adopted, effective January 1, 1993, the accounting standard FAS 112, "Employers' Accounting For Postemployment Benefits."
UNION TEXAS PETROLEUM HOLDINGS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (DOLLARS IN THOUSANDS UNLESS OTHERWISE INDICATED)
NOTE 19 -- 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, 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 1994, the Company purchased an interest in the undeveloped Britannia field in the U.K. North Sea, adding at year end 1994 approximately 38 million barrels of oil equivalent ("boe") to its proved reserves.
In 1992, 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, after 1992, the Company booked upward revisions of proved reserves attributable to its interest in this joint venture.
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 that of Pertamina and not the joint venture. 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 are subject to revision as prices 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. Indonesian reserves associated with the Unimar partnership are shown under the caption "Non-Consolidated Interests."
"Other International" primarily represents a service contract in Argentina under which a service fee for each barrel of production was received by Unola and an interest in Egypt. In January 1992, the Company completed the sale of Unola.
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
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
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(a) Includes gas consumed in the operation of the LNG plant, which was approximately 11 Bcf and 4 Bcf, 10 Bcf and 4 Bcf and 10 Bcf and 4 Bcf attributable to the Company and its Unimar partnership, respectively, for 1994, 1993 and 1992; and gas sold to a fertilizer plant and a refinery.
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:
- --------------- (a) Includes $1 million for capitalized interest.
(b) Includes $19 million, $25 million and $16 million for capitalized interest in 1994, 1993 and 1992, respectively.
(c) Includes $1 million for capitalized interest.
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:
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 1994, 1993 and 1992 were as follows:
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(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.
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 1994, 1993 and 1992 were as follows:
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(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.
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:
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, 1994, were $15.40 per barrel of U.K. crude oil and $2.47 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.
NOTE 20 -- SUPPLEMENTAL GUARANTOR INFORMATION
In connection with the sale by UTPH of the Notes, the following subsidiaries of UTPH (collectively, the "Guarantors") unconditionally guaranteed (the "Guarantees") on a joint and several basis UTPH's obligations to pay principal, premium, if any, and interest with respect to the Notes: Union Texas East Kalimantan Limited, Union Texas Petroleum Energy Corporation, Union Texas International Corporation, Union Texas Products Corporation and Unistar, Inc. The Guarantors are also guarantors under the Credit Facilities. Supplemental combining financial information of the Guarantors is presented below:
UNION TEXAS PETROLEUM HOLDINGS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (DOLLARS IN THOUSANDS UNLESS OTHERWISE INDICATED)
SUPPLEMENTAL COMBINING BALANCE SHEET DECEMBER 31, 1994
ASSETS
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* The Company follows the successful efforts method of accounting for oil and gas activities.
UNION TEXAS PETROLEUM HOLDINGS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (DOLLARS IN THOUSANDS UNLESS OTHERWISE INDICATED)
SUPPLEMENTAL COMBINING BALANCE SHEET DECEMBER 31, 1993
ASSETS
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*The Company follows the successful efforts method of accounting for oil and gas activities.
UNION TEXAS PETROLEUM HOLDINGS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (DOLLARS IN THOUSANDS UNLESS OTHERWISE INDICATED)
SUPPLEMENTAL COMBINING STATEMENT OF OPERATIONS FOR THE YEAR ENDED DECEMBER 31, 1994
UNION TEXAS PETROLEUM HOLDINGS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (DOLLARS IN THOUSANDS UNLESS OTHERWISE INDICATED)
SUPPLEMENTAL COMBINING STATEMENT OF OPERATIONS FOR THE YEAR ENDED DECEMBER 31, 1993
UNION TEXAS PETROLEUM HOLDINGS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (DOLLARS IN THOUSANDS UNLESS OTHERWISE INDICATED)
SUPPLEMENTAL COMBINING STATEMENT OF OPERATIONS FOR THE YEAR ENDED DECEMBER 31, 1992
UNION TEXAS PETROLEUM HOLDINGS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (DOLLARS IN THOUSANDS UNLESS OTHERWISE INDICATED)
SUPPLEMENTAL COMBINING STATEMENT OF CASH FLOWS FOR THE YEAR ENDED DECEMBER 31, 1994
UNION TEXAS PETROLEUM HOLDINGS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (DOLLARS IN THOUSANDS UNLESS OTHERWISE INDICATED)
SUPPLEMENTAL COMBINING STATEMENT OF CASH FLOWS FOR THE YEAR ENDED DECEMBER 31, 1993
UNION TEXAS PETROLEUM HOLDINGS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (DOLLARS IN THOUSANDS UNLESS OTHERWISE INDICATED)
SUPPLEMENTAL COMBINING STATEMENT OF CASH FLOWS FOR THE YEAR ENDED DECEMBER 31, 1992
NOTES TO SUPPLEMENTAL GUARANTOR INFORMATION
(1) In connection with the sale of Notes by UTPH, the following subsidiaries of UTPH (collectively, the "Guarantors") unconditionally guaranteed on a joint and several basis UTPH's obligations to pay principal, premium, if any, and interest with respect to the Notes: Union Texas East Kalimantan Limited ("Kalimantan"), Union Texas Petroleum Energy Corporation ("Energy"), Union Texas International Corporation ("International"), Union Texas Products Corporation ("Products") and Unistar, Inc. ("Unistar"). Each of the Guarantors is a Delaware corporation, except that Kalimantan is incorporated under the laws of the Bahamas, although, the applicable laws of the Bahamas are similar to the laws of Delaware with respect to the availability of assets to satisfy the obligations to the Noteholders. Kalimantan and Unistar together own a 37.81% interest in a joint venture that represents the Company's operations in Indonesia. Products conducts the Company's domestic hydrocarbon products businesses. International, a subsidiary of Energy, is a holding company for subsidiaries that conduct the Company's principal international operations, which include operations in Indonesia by Kalimantan, a Guarantor, and in the United Kingdom and Pakistan by two non-Guarantor subsidiaries. Separate financial statements of the Guarantors of the Notes are not considered to be material to the Noteholders. See Notes 14 and 19 for information describing the Company's operations through the two Guarantor subsidiaries in Indonesia relating to a production sharing contract as well as through the non-Guarantor subsidiaries in the United Kingdom, Pakistan and other international locations.
(2) Investments in subsidiaries are accounted for by the Company on the cost basis for purposes of the supplemental information. Earnings of subsidiaries are therefore not reflected in the related investment accounts.
(3) Certain reclassifications were made to conform all of the financial information to the financial presentation on a consolidated basis. The principal eliminating entries eliminate investments in subsidiaries, intercompany balances and intercompany dividends.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
ITEM 13.
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 1995 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission within 120 days after December 31, 1994, and portions of which are incorporated herein by reference.
PART IV
ITEM 14.
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, 1994 and 1993 -- page 34.
Consolidated Statement of Operations -- For the years ended December 31, 1994, 1993 and 1992 -- page 35.
Consolidated Statement of Cash Flows -- For the years ended December 31, 1994, 1993 and 1992 -- page 36.
Consolidated Statement of Stockholders' Equity -- For the years ended December 31, 1994, 1993 and 1992 -- page 37.
Selected Quarterly Financial Data for the two years ended December 31, 1994 -- page 51.
Selected Financial Data for the five years ended December 31, 1994 -- page 24.
(A) 2 EXHIBITS.
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(B) REPORTS ON FORM 8-K.
The Company filed Current Reports on Form 8-K dated: (i) October 19, 1994, to attach press releases announcing the extension of the Company's exploration concession by the Pakistan government and the increase in the Company's working interest in acreage in Alaska's Western Colville Delta area and to report the execution of the $100 million credit facility and the agreement to acquire interests in the Britannia field in the U.K. North Sea from Fina Exploration Limited and Fina Petroleum Development Limited (collectively "Fina"); (ii) October 25, 1994, to attach a press release announcing the 1994 third quarter results; (iii) November 14, 1994, to report the completion of the acquisition of a unit interest in the Britannia field and the appointment of a succession committee and to attach press releases regarding the Company's high bids on acreage in the Kenai Peninsula, Alaska, and the acquisition of a unit interest in the Britannia field; (iv) December 9, 1994, to report the agreement to acquire an interest in the Britannia field in the U.K. North Sea from AGIP (U.K.) Limited ("AGIP") and the exercise of a preemptive purchase right by another interest holder regarding an interest in the Britannia field that was to be acquired by the Company from Fina; (v) December 27, 1994, to report the approval of Britannia development costs by the U.K. Department of Trade and Industry and the exercise of a preemptive purchase right by another interest holder regarding the interest that was to be acquired by the Company from AGIP and to attach a press release to announce a new exploration license in the Eastern Sindh block granted to the Company by the Pakistan government; (vi) January 20, 1995, to attach a press release announcing 1994 production and year-end reserve amounts; (vii) February 7, 1995, to attach press releases announcing the 1994 year-end and fourth quarter results, the 1995 capital spending budget and the agreement to acquire an interest in St. George's Channel offshore Ireland; and (viii) February 22, 1995, to attach press releases announcing title change to Vice President and Chief Financial Officer of the Company, the Company's agreement to acquire interests in three onshore exploration permit areas in Italy and the Company's three discoveries in Pakistan.
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.
POWER OF ATTORNEY
We, the undersigned, directors and officers of Union Texas Petroleum Holdings, Inc. (the "Company"), do hereby severally constitute and appoint A. Clark Johnson, Larry D. Kalmbach and Donald M. McMullan and each or any 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, 1994, 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.
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 and 33-64928) and Form S-3 (No. 33-52683) of our report dated January 25, 1995, appearing on page 33 of this Form 10-K.
PRICE WATERHOUSE LLP
Houston, Texas March 9, 1995
S-1 INDEX TO EXHIBITS
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