-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, IqMGhpMXdtnl5zhvmpuYi6S7b8pZJeuLCw2X9Lby6ocS3bo5YE9e0e80hQIMBcTv 9pmAIfK0m/iGEo4QXZAVdg== 0000716039-03-000122.txt : 20031114 0000716039-03-000122.hdr.sgml : 20031114 20031114141511 ACCESSION NUMBER: 0000716039-03-000122 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 6 CONFORMED PERIOD OF REPORT: 20031114 FILED AS OF DATE: 20031114 FILER: COMPANY DATA: COMPANY CONFORMED NAME: UNOCAL CORP CENTRAL INDEX KEY: 0000716039 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 953825062 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 001-08483 FILM NUMBER: 031003055 BUSINESS ADDRESS: STREET 1: 2141 ROSECRANS AVE STREET 2: STE 4000 CITY: EL SEGUNDO STATE: CA ZIP: 90245 BUSINESS PHONE: 3107267600 MAIL ADDRESS: STREET 1: 2141 ROSECRANS AVE STREET 2: STE 4000 CITY: EL SEGUNDO STATE: CA ZIP: 90245 10-Q 1 q32003_10q.txt 3RD QUARTER 10-Q UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D. C. 20549 FORM 10-Q (Mark One) [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended September 30, 2003 -------------------- OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to -------------- ------------------- Commission file number 1-8483 UNOCAL CORPORATION (Exact name of registrant as specified in its charter) DELAWARE 95-3825062 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 2141 ROSECRANS AVENUE, SUITE 4000, EL SEGUNDO, CALIFORNIA 90245 (Address of principal executive offices) (Zip Code) (310) 726-7600 (Registrant's Telephone Number, Including Area Code) Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No ------- ------- Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes X No ------- ------- Number of shares of Common Stock, $1 par value, outstanding as of October 31, 2003: 258,951,128 TABLE OF CONTENTS PAGE Glossary.................................................................... i PART I FINANCIAL INFORMATION Item 1. Financial Statements Consolidated Earnings............................................. 1 Consolidated Balance Sheet........................................ 2 Consolidated Cash Flows........................................... 3 Notes to Financial Statements..................................... 4 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations....................... 38 Operating Highlights ............................................... 40 Item 3. Quantative and Qualitative Disclosures About Market Risk............ 56 Item 4. Controls and Procedures............................................. 60 PART II OTHER INFORMATION Item 1. Legal Proceedings................................................... 61 Item 5. Other Information................................................... 61 Item 6. Exhibits and Reports on Form 8-K.................................... 62 SIGNATURE................................................................... 63 EXHIBIT INDEX............................................................... 64 GLOSSARY Below are certain definitions of key terms that may be in use in this Form 10-Q report. M Thousand Bbl Barrels MM Million Cf/d Cubic feet per day B Billion Cfe/d Cubic feet of gas T Trillion equivalent per day CF Cubic feet Btu British thermal units BOE Barrels of oil equivalent DD&A Depreciation, depletion and amortization Liquids Crude oil, condensate and NGLs NGLs Natural gas liquids Bbl/d Barrels per day o API Gravity is a measurement of the gravity (density) of crude oil and other liquid hydrocarbons by a system recommended by the American Petroleum Institute ("API"). The measuring scale is calibrated in terms of "API degrees." The higher the API gravity, the lighter the oil. o Bilateral institution refers to a country specific institution, which lends funds primarily to promote the export of goods from that country. Examples of bilateral institutions are Ex-Im (U.S.), Hermes (Germany), SACE (Italy), COFACE (France), and JBIC (Japan). o BOE is a term used to quantify oil and natural gas amounts using the same measurement. Gas volumes are converted to barrels of oil equivalent on the basis of energy content, where the volume of natural gas that when burned produces the same amount of heat as a barrel of oil (6,000 cubic feet of gas equals one barrel of oil equivalent). o British Thermal Units ("Btu") is a standardized unit of measure for energy, equivalent to the amount of heat required to raise the temperature of one pound of water one degree Fahrenheit. Ten thousand MMBtu (million Btu) is the standard volume for exchange traded derivative contracts, the approximate heat content of ten thousand Mcf (thousand cubic feet) of natural gas. o Delineation or appraisal well is a well drilled in an unproven area adjacent to a discovery well to define the boundaries of the reservoir. o Development well is a well drilled within the proved area of an oil or natural gas reservoir to a depth of a stratigraphic horizon known to be productive. o Dry hole is a well incapable of producing hydrocarbons in sufficient commercial quantities to justify future capital expenditures for completion and additional infrastructure. o Economic interest method pursuant to production sharing contracts is a method by which the Company's share of the cost recovery revenue and the profit revenue is divided by market oil and gas prices and represents the volume that the Company is entitled to. The lower the commodity price, the higher the volume entitlement, and vice versa. o Exploratory well is a well drilled to find and produce oil or natural gas reserves that is not a development well. o Farm-in or farm-out is an agreement whereby the owner of a working interest in an oil and gas lease assigns the working interest or a portion thereof to another party who desires to drill on the leased acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a "farm-in," while the interest transferred by the assignor is a "farm-out." o Field is an area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature or stratigraphic condition. o Floating Production Storage and Offloading ("FPSO") technology refers to the use of a vessel that is stationed above or near an offshore oil field. Produced fluids from subsea completion wells are brought by flowlines to the vessel where they are separated, treated, stored and then offloaded to another vessel for transportation. o Gross acres or gross wells are the total acres or wells in which a working interest is owned. i o Hydrocarbons are organic compounds of hydrogen and carbon atoms that form the basis of all petroleum products. o Lifting is the amount of liquids each working-interest partner takes physically. The liftings may actually be more or less than actual entitlements that are based on royalties, working interest percentages, and a number of other factors. o Liquefied Natural Gas ("LNG") is a gas, mainly methane, which has been liquefied in a refrigeration and pressure process to facilitate storage and transportation. o Liquefied Petroleum Gas ("LPG") is a mixture of butane, propane and other light hydrocarbons. At normal temperature it is a gas, but when cooled or subjected to pressure it can be stored and transported as a liquid. o Multilateral institution refers to an institution with shareholders from multiple countries that lends money for specific development reasons. Examples of multilateral institutions are International Finance Corporation ("IFC"), European Bank for Reconstruction and Development ("EBRD"), and Asian Development Bank ("ADB"). o Natural Gas Liquids ("NGLs") are primarily ethane, propane, butane and natural gasolines which can be extracted from wet natural gas and become liquid under various combinations of increasing pressure and lower temperature. o Net acreage and net oil and gas wells are obtained by multiplying gross acreage and gross oil and gas wells by the Company's working interest percentage in the properties. o Net pay is the amount of oil or gas saturated rock capable of producing oil or gas. o Production Sharing Contract ("PSC") is a contractual agreement between the Company and a host government whereby the Company, acting as contractor, bears all exploration costs, development and production costs in return for an agreed upon share of the proceeds from the sale of production. o Producible well is a well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes. o Prospective acreage is lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas. o Proved acreage is acreage that is allocated to producing wells or wells capable of production or to acreage that is being developed. o Reservoir is a porous and permeable underground formation containing oil and/or natural gas enclosed or surrounded by layers of less permeable rock and is individual and separate from other reservoirs. o Subsea tieback is a well with the wellhead equipment located on the bottom of the ocean. o Take-or-Pay is a type of contract clause where specific quantities of a product must be paid for, even if delivery is not taken. Normally, the purchaser has the right in following years to take product that had been paid for but not taken. o Trend or Play is an area or region of concentrated activity with a group of related fields and prospects. o Working interest is the percentage of ownership that the Company has in a joint venture, partnership, consortium, project or acreage. ii PART I - FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS
CONSOLIDATED EARNINGS (UNAUDITED) UNOCAL CORPORATION For the Three Months For the Nine Months Ended September 30, Ended September 30, ------------------------------------------------- Millions of dollars except per share amounts 2003 2002 2003 2002 - -------------------------------------------------------------------------------- Revenues Sales and operating revenues $ 1,478 $ 1,299 $ 4,817 $ 3,695 Interest, dividends and miscellaneous income (2) (3) 18 17 Gain on sales of assets 65 1 115 2 - -------------------------------------------------------------------------------- Total revenues 1,541 1,297 4,950 3,714 Costs and other deductions Crude oil, natural gas and product purchases 447 401 1,629 1,124 Operating expense 346 326 965 949 Administrative and general expense 61 34 199 114 Depreciation, depletion and amortization 231 245 746 724 Asset impairments 83 6 86 27 Dry hole costs 14 40 95 81 Exploration expense 39 60 182 180 Interest expense 45 40 119 134 Property and other operating taxes 18 7 61 41 Distributions on convertible preferred securities of subsidiary trust 8 8 24 24 - -------------------------------------------------------------------------------- Total costs and other deductions 1,292 1,167 4,106 3,398 Earnings from equity investments 54 35 150 123 - -------------------------------------------------------------------------------- Earnings from continuing operations before income taxes and minority interests 303 165 994 439 - -------------------------------------------------------------------------------- Income taxes 147 68 448 203 Minority interests 4 (2) 8 2 - -------------------------------------------------------------------------------- Earnings from continuing operations 152 99 538 234 - -------------------------------------------------------------------------------- Earnings from discontinued operations - - 8 1 Cumulative effects of accounting changes (a) - - (83) - - -------------------------------------------------------------------------------- Net earnings $ 152 $ 99 $ 463 $ 235 ================================================================================ Basic earnings per share of common stock (b) Continuing operations $ 0.59 $ 0.41 $ 2.08 $ 0.96 Net earnings $ 0.59 $ 0.41 $ 1.79 $ 0.96 Diluted earnings per share of common stock (c) Continuing operations $ 0.58 $ 0.41 $ 2.05 $ 0.96 Net earnings $ 0.58 $ 0.41 $ 1.78 $ 0.96 Cash dividends declared per share of common stock $ 0.20 $ 0.20 $ 0.60 $ 0.60 - -------------------------------------------------------------------------------- (a) Net of tax (benefit) $ - $ - $ (48) $ - (b) Basic weighted average shares outstanding (in thousands) 258,525 244,664 258,244 244,503 (c) Diluted weighted average shares outstanding (in thousands) 272,691 245,226 272,172 245,378 See Notes to the Consolidated Financial Statements.
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CONSOLIDATED BALANCE SHEET UNOCAL CORPORATION At September 30, At December 31, ------------------------------------- Millions of dollars 2003 (a) 2002 - -------------------------------------------------------------------------------- Assets Current assets Cash and cash equivalents $ 485 $ 168 Accounts and notes receivable - net 1,009 994 Inventories 132 97 Deferred income taxes 122 90 Other current assets 31 26 - -------------------------------------------------------------------------------- Total current assets 1,779 1,375 Investments and long-term receivables - net 903 1,044 Properties - net (b) 8,492 7,879 Goodwill 129 122 Deferred income taxes 261 210 Other assets 146 130 - -------------------------------------------------------------------------------- Total assets $ 11,710 $ 10,760 ================================================================================ Liabilities and Stockholders' Equity Current liabilities Accounts payable $ 1,044 $ 1,024 Taxes payable 278 223 Dividends payable 51 51 Interest payable 52 50 Current portion of environmental liabilities 144 113 Current portion of long-term debt and capital leases 249 6 Other current liabilities 159 165 - -------------------------------------------------------------------------------- Total current liabilities 1,977 1,632 Long-term debt and capital leases 2,868 3,002 Deferred income taxes 709 593 Accrued abandonment, restoration and environmental liabilities 912 622 Other deferred credits and liabilities 915 816 Minority interests 28 275 Commitments and contingencies - Note 17 Company-obligated mandatorily redeemable convertible preferred securities of a subsidiary trust holding solely parent debentures 522 522 Common stock ($1 par value, shares authorized: 750,000,000 (c)) 269 269 Capital in excess of par value 985 962 Unearned portion of restricted stock issued (14) (20) Retained earnings 3,329 3,021 Accumulated other comprehensive income (353) (486) Notes receivable - key employees (26) (37) Treasury stock - at cost (d) (411) (411) - -------------------------------------------------------------------------------- Total stockholders' equity 3,779 3,298 - -------------------------------------------------------------------------------- Total liabilities and stockholders' equity $ 11,710 $ 10,760 ================================================================================ (a) Unaudited (b) Net of accumulated depreciation, depletion and amortization of: $ 13,120 $ 12,277 (c) Number of shares outstanding (in thousands) 258,718 257,980 (d) Number of shares (in thousands) 10,623 10,623 The Company follows the successful efforts method of accounting for its oil and gas activities. See Notes to the Consolidated Financial Statements.
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CONSOLIDATED CASH FLOWS (UNAUDITED) UNOCAL CORPORATION For the Nine Months Ended September 30, ---------------------- Millions of dollars 2003 2002 - -------------------------------------------------------------------------------- Cash Flows from Operating Activities Net earnings $ 463 $ 235 Adjustments to reconcile net earnings to net cash provided by operating activities Depreciation, depletion and amortization 746 724 Asset impairments 86 27 Dry hole costs 95 81 Amortization of exploratory leasehold costs 88 74 Deferred income taxes 102 25 Gain on sales of assets (115) (2) Gain on disposal of discontinued operations (13) (2) Pension expense 65 17 Restructuring provisions net of payments 22 14 Cumulative effect of accounting changes 83 - Other 5 (85) Working capital and other changes related to operations Accounts and notes receivable (15) 160 Inventories (35) (2) Accounts payable 20 44 Taxes payable 55 4 Other 1 (82) - -------------------------------------------------------------------------------- Net cash provided by operating activities 1,653 1,232 - -------------------------------------------------------------------------------- Cash Flows from Investing Activities Capital expenditures (includes dry hole costs) (1,296) (1,248) Proceeds from sales of assets 343 61 Proceeds from sale of discontinued operations 11 3 - -------------------------------------------------------------------------------- Net cash used in investing activities (942) (1,184) - -------------------------------------------------------------------------------- Cash Flows from Financing Activities Long-term borrowings 154 437 Reduction of long-term debt and capital lease obligations (156) (267) Minority interests (257) (6) Proceeds from issuance of common stock 15 19 Dividends paid on common stock (155) (147) Other 5 1 - -------------------------------------------------------------------------------- Net cash provided by (used in) financing activities (394) 37 - -------------------------------------------------------------------------------- Net increase (decrease) in cash and cash equivalents 317 85 - -------------------------------------------------------------------------------- Cash and cash equivalents at beginning of year 168 190 - -------------------------------------------------------------------------------- Cash and cash equivalents at end of period $ 485 $ 275 ================================================================================ Supplemental disclosure of cash flow information: Cash paid during the period for: Interest (net of amount capitalized) $ 123 $ 136 Income taxes (net of refunds) $ 310 $ 211 See Notes to the Consolidated Financial Statements.
-3- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) 1. General The consolidated financial statements included in this report are unaudited and, in the opinion of management, include all adjustments necessary for a fair presentation of financial position and results of operations. All adjustments are of a normal recurring nature. Such financial statements are presented in accordance with the Securities and Exchange Commission's ("SEC") disclosure requirements for Form 10-Q. These interim consolidated financial statements should be read in conjunction with the consolidated financial statements and the related notes filed with the SEC in Unocal Corporation's 2002 Annual Report on Form 10-K. For the purpose of this report, Unocal Corporation ("Unocal") and its consolidated subsidiaries, including Union Oil Company of California ("Union Oil"), are referred to as the "Company." The consolidated financial statements of the Company include the accounts of subsidiaries in which a controlling interest is held. Investments in entities without a controlling interest are accounted for by the equity method or cost basis. Under the equity method, the investments are stated at cost plus the Company's equity in undistributed earnings and losses after acquisition. Income taxes estimated to be payable when earnings are distributed are included in deferred income taxes. Results for the nine months ended September 30, 2003, are not necessarily indicative of future financial results. Certain items in the financial statements of the prior periods have been reclassified to conform to the 2003 presentation. 2. Accounting Changes SFAS No. 143: Effective January 1, 2003, the Company adopted Statement of Financial Accounting Standards ("SFAS") No. 143, "Accounting for Asset Retirement Obligations." If a reasonable estimate of fair value can be made, this Statement requires that the Company recognize liabilities related to the legal obligations associated with the retirement of its tangible long-lived assets in the periods in which the obligations are incurred (typically when the assets are installed). These obligations include the required decommissioning and removal of certain oil and gas platforms, plugging and abandonment of oil and gas wells and facilities and the closure and site restoration of certain mining facilities. The recognized liability amounts are based upon future retirement cost estimates and incorporate many assumptions such as expected economic recoveries of crude oil and natural gas, time to abandonment, future inflation rates and the risk free rate of interest adjusted for the Company's credit costs. The Company has interests in some long-lived assets, such as commercial natural gas storage facilities, commercial crude oil and products storage facilities, commercial pipelines, etc. where the operations are not tied to any particular operating field reserves. As the Company expects these assets to continue operations for the foreseeable future, it cannot reasonably estimate when, or if, these facilities will be abandoned. Accordingly, the Company has not accrued abandonment and restoration liabilities for these assets. The Company will continue to monitor these assets for any changes to this position. Prior to January 1, 2003, the Company was required under SFAS No. 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies," to accrue its abandonment and restoration costs ratably over the productive lives of its assets using the units-of-production method. SFAS No. 19 resulted in higher costs being accrued early in the fields' lives when production was at its highest levels and abandonment and restoration costs accruals were matched with the revenues as oil and gas were produced. -4- Under SFAS No. 143, when the liabilities for asset retirement obligations are initially recorded at their fair value, capital costs of the related assets will be increased by equal corresponding amounts. Over time, changes in the present value of the liabilities will be accreted and expensed and the capitalized asset costs will be depreciated over the useful lives of the corresponding assets. Because SFAS No. 143 requires the use of interest accretion for revaluing asset retirement obligation liabilities as a result of the passage of time, associated accretion costs will be higher near the end of the fields' lives when oil and gas production and related revenues are at their lowest levels. Accounting Principles Board ("APB") Opinion No. 20, "Accounting Changes" requires that the Company calculate the retroactive impact of adopting SFAS No. 143 from the inception of its asset retirement obligations to its January 1, 2003 adoption date. APB Opinion No. 20 requires that this impact be quantified and reported as a cumulative effect of an accounting change on the earnings statement. This cumulative effect includes the catch up of SFAS No. 143 accretion expense related to the fair value of the liabilities as well as the catch up of associated depreciation expense related to the increased capital costs of the corresponding assets. The cumulative effect also includes the reversal of abandonment and restoration costs previously charged to earnings under SFAS No. 19. In addition to the impact on earnings due to the differences in applying SFAS No. 19 and SFAS No. 143 to the Company's oil and gas operations, the cumulative effect also includes the impact related to the Company's mining operations under SFAS No. 143. In the first quarter of 2003, the Company recognized a one time after-tax charge of $83 million as the cumulative effect of an accounting change related to the adoption of SFAS No. 143. The Company also increased its accrued abandonment and restoration liabilities by $268 million and increased its net properties by $138 million on the consolidated balance sheet as a result of the adoption of SFAS 143 as of January 1, 2003. The Company estimates that the impact of adopting SFAS No. 143 on its 2003 operating earnings will be an incremental charge of approximately $10 million after tax. Listed below is SFAS No. 143 pro-forma liability and earnings information for the periods ended December 31, 2000, 2001 and 2002 and September 30, 2002:
Pro Forma SFAS 143 liability carrying amounts for the periods shown (Millions of dollars) 2000 2001 2002 - -------------------------------------------------------------------------------- Carrying amount of liability at beginning of year $629 $661 $713 - -------------------------------------------------------------------------------- Carrying amount of liability at end of period $661 $713 $758 - --------------------------------------------------------------------------------
Pro Forma amounts assuming SFAS 143 was applied retroactively Millions of dollars (except per share amounts) For the years ended For the Nine December 31, Months Ended 2000 2001 2002 Sep. 30, 2002 - -------------------------------------------------------------------------------- Net income as reported $760 $615 $331 $235 Earnings per share as reported: Basic $3.13 $2.52 $1.34 $0.96 Diluted $3.08 $2.50 $1.34 $0.96 Pro forma net income $740 $596 $312 $221 Pro forma earnings per share: Basic $3.05 $2.44 $1.26 $0.90 Diluted $3.00 $2.42 $1.26 $0.90 - --------------------------------------------------------------------------------
SFAS No. 146: Effective January 1, 2003, the Company adopted SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities." This Statement provides guidance on the recognition and measurement of liabilities associated with disposal activities. The adoption of the Statement did not have a material effect on the Company's financial position or results of operations. -5- SFAS No. 148: Effective January 1, 2003, the Company adopted SFAS No. 148, "Accounting for Stock-Based Compensation--Transition and Disclosure--an amendment of FASB Statement No. 123." The Statement provides for three methods of transitioning from the intrinsic value to the fair value method of accounting for stock-based compensation. This Statement also amended the disclosure requirements of SFAS No. 123 and APB Opinion No. 28, "Interim Financial Reporting," to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. The disclosure requirements of the Statement were adopted in the Company's 2002 Annual Report on Form 10-K. The Company adopted the fair value recognition provisions of SFAS No. 148, on a prospective basis, effective January 1, 2003 (see note 9 for further details). This change is estimated to decrease 2003 after-tax income by approximately $6 million. Adoption of the fair value recognition provisions will not have a material effect on the Company's 2003 financial position or results of operations. SFAS No. 149: Effective July 1, 2003, the Company adopted SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities." This Statement amends and clarifies accounting for derivative instruments including certain derivative instruments embedded in other contracts, and for hedging activities under SFAS No. 133. The adoption of the Statement did not have a material effect on the Company's financial position or results of operations. SFAS No. 150: Effective April 1, 2003, the Company adopted SFAS No. 150, "Accounting for Certain Instruments with Characteristics of Both Liabilities and Equity," which establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. SFAS No. 150 requires that the Company classify a financial instrument that is within its scope, which may have previously been reported as equity, as a liability or an asset in some circumstances. The adoption of the Statement did not have an effect on the Company's financial position. FASB Interpretation No. 45: Effective January 1, 2003, the Company adopted FASB Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others." This Interpretation requires the recognition of certain guarantees as liabilities at fair market value and is effective for guarantees issued or modified after December 31, 2002. The Company has included the disclosure requirements of the Interpretation in note 17. The adoption of this Interpretation did not have a material effect on the Company's financial position or results of operations. FASB Interpretation No. 46: Effective January 1, 2003, the Company adopted FASB Interpretation No. 46, "Consolidation of Variable Interest Entities." This Interpretation requires the consolidation of certain entities that generally lack sufficient equity to finance their own activity without support from others or where there is an absence of control by equity investors. This Interpretation was effective for new variable interest entities as of February 1, 2003. Effective July 1, 2003, the Company adopted the Interpretation for the entities that existed prior to February 1, 2003. The Company has included the disclosure requirements of the Interpretation in this report. Pursuant to the recognition requirements of FASB Interpretation No. 46, the Company consolidated in the third quarter of 2003 the long-term debt of an affiliate that operates geothermal steam-fired power plants in Indonesia. At September 30, 2003, the balance sheet includes $78 million related to this debt (see note 15 for further details). An additional $242 million, classified as minority interests as of June 30, 2003, related to a partnership interest in Spirit Energy 76 Development, L.P. ("Spirit LP"), would have been required to be consolidated as long-term debt under this Interpretation had it not been paid in July 2003. In addition, because of the complexities of this rule and the FASB deferral, as set forth in FASB Staff Position No. FIN 46-6, of mandatory adoption until December 31, 2003, the Company continues to review and may find additional material interests in entities which could require recognition or disclosure in the financial statements. -6- Other Matters: Consistent with SFAS No. 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies," costs of acquiring oil and gas drilling rights have been classified as tangible assets in property, plant and equipment. The Company understands the staff of the SEC believes SFAS No. 19 does not provide guidance as to whether these assets should be classified as tangible or intangible and therefore believe SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and Other Intangible Assets," would require that drilling rights be classified as an intangible asset. The SEC has requested the FASB to address this perceived conflict within the related FASB statements. The resolution of this issue will have no impact on the Company's results of operations. If the FASB concurs with the SEC, it would result in additional disclosures and a balance sheet reclassification of these assets from Properties-net to Intangible Assets. 3. Other Financial Information During the third quarters of 2003 and 2002, approximately 20 percent and 24 percent, respectively, of total sales and operating revenues were attributable to the resale of liquids and natural gas purchased from others in connection with marketing activities. For the nine months ended September 30, 2003 and 2002, these percentages were each approximately 23 percent. Related purchase costs are classified as expense in the crude oil, natural gas and product purchase category on the consolidated earnings statement. Capitalized interest totaled $11 million and $14 million for the third quarters of 2003 and 2002, respectively. For the nine months ended September 30, 2003 and 2002, capitalized interest totaled $46 million and $33 million, respectively. The increase for the comparative nine months periods was primarily due to the capitalized interest related to the Azerbaijan International Operating Company ("AIOC") development of Phase I of the offshore Azeri field in the Azeri-Chirag-Gunashli structure in the Azerbaijan sector of the Caspian Sea. Exploration expense on the consolidated earnings statement consisted of the following:
For the Three Months For the Nine Months Ended September 30, Ended September 30, -------------------- ------------------- Millions of dollars 2003 2002 2003 2002 - -------------------------------------------------------------------------------- Exploration operations $ 13 $ 18 $ 44 $ 66 Geological and geophysical 7 10 41 29 Amortization of exploratory leasehold costs 17 29 88 74 Leasehold rentals 2 3 9 11 - -------------------------------------------------------------------------------- Exploration expense $ 39 $ 60 $182 $180 ================================================================================
For the nine months ended September 30, 2003, amortization of exploratory leasehold costs included a $26 million pre-tax provision that was a result of the Company's relinquishment of 44 deepwater Gulf of Mexico blocks before their expiration dates. The Company intends to focus its deepwater Gulf of Mexico land position on those Outer Continental Shelf blocks that have the best potential. The prior year nine months period included a provision of $14 million pre-tax reflecting the relinquishment of exploration blocks in Brazil and Gabon. -7- 4. Dispositions Of Assets In the third quarter of 2003, the Company's Chicago Carbon Company subsidiary sold 4.9 million of the common shares it held in Tom Brown, Inc. ("TBI"). The sale was part of the underwritten stock offering commenced by TBI in early September and represented approximately 85 percent of the 5.8 million shares held by the Unocal subsidiary. The Company realized proceeds of $122 million pre-tax from the sale. The price was $25.75 per share less transaction costs. The Company recorded a pre-tax gain of approximately $22 million in the current quarter results related to this sale. The Company expects to sell the remaining 875,000 TBI shares it holds as market conditions allow following a 90-day lock-up period. In the second quarter of 2003, the Company sold its Matador Petroleum Corporation ("Matador") shares for approximately $80 million pre-tax. The Company recorded a $41 million pre-tax gain from the sale of its interest for the nine months period of 2003. 5. Impairment of Assets The Company, as part of its regular assessment and in conjunction with its assessment of the Gulf of Mexico properties held for sale (see note 12) recorded pre-tax impairment charges of $86 million, or $54 million after-tax, in the nine months period of 2003. Pre-tax impairments of approximately $79 million were related to oil and gas fields in the Gulf of Mexico region. In addition, the Company recorded impairments of approximately $5 million pre-tax relating to the Trans-Andean oil pipeline, which transports crude oil from Argentina to Chile and $2 million for pipeline assets associated with producing exploration and production properties held for sale in the Gulf of Mexico. The Company's interests in petroleum pipelines are part of the Midstream segment. In the nine months period of 2002, the Company recorded pre-tax impairment charges of $27 million, or $17 million after-tax. Impairments of $23 million pre-tax were primarily related to oil and gas fields in Alaska and the Gulf of Mexico region. The Company also recorded a pre-tax impairment charge of $4 million due to a U.S. pipeline company, in which the Company owns an equity interest. 6. Restructuring In June 2003, the Company accrued a $27 million pre-tax restructuring charge and adopted a plan for streamlining the organizational structures in order to align them with the Company's portfolio requirements and business needs. In the third quarter of 2003, the Company accrued an additional $10 million pre-tax restructuring charge to reflect continued streamlining of the organizational structures. The charge is included in selling, administrative and general expense on the consolidated earnings statement. The following table reflects the 2003 restructuring activity by quarter: - ----------------------- ----------------- ----------- ------------ ------------- Millions of dollars # Employees added Training / Post- (except employees) to restructuring Termination Outplacement retirement plan Costs Costs Benefit Costs - ----------------------- ----------------- ----------- ------------ ------------- 1st Quarter Accrual - - - - - ----------------------- ----------------- ----------- ------------ ------------- 1st Quarter Payments - - - - ----------------------- ----------------- ----------- ------------ ------------- Liability at 3/31/2003 - - - - ----------------------- ----------------- ----------- ------------ ------------- 2nd Quarter Accrual 219 21 2 4 - ----------------------- ----------------- ----------- ------------ ------------- 2nd Quarter Payments - - - - ----------------------- ----------------- ----------- ------------ ------------- Liability at 6/30/2003 21 2 4 - ----------------------- ----------------- ----------- ------------ ------------- 3rd Quarter Accrual 127 9 - 1 - ----------------------- ----------------- ----------- ------------ ------------- 3rd Quarter Payments 2 - - - ----------------------- ----------------- ----------- ------------ ------------- Liability at 9/30/2003 28 2 5 - ----------------------- ----------------- ----------- ------------ ------------- The majority of the liabilities are expected to be paid in 2003 and 2004. At September 30, 2003, 321 of 346 employees had been terminated or had been advised of planned termination dates as a result of the plan. -8- In June 2002, the Company's Gulf Region business unit, which is part of the U.S. Lower 48 operations in the Exploration and Production segment, adopted a restructuring plan that resulted in the accrual of a $19 million pre-tax restructuring charge. The charge included the estimated costs of terminating 202 employees, all of whom were terminated in 2002. At September 30, 2003, approximately $18 million of the restructuring costs had been paid and charged against the liability, leaving accrued costs of $1 million on the consolidated balance sheet. The remaining costs are expected to be paid by the end of 2003. In November 2002, the Company adopted a restructuring plan that resulted in the accrual of a $4 million pre-tax restructuring charge related to Exploration and Production operations in Alaska. The restructuring charge reflected the costs of terminating 46 employees, of whom 43 had been terminated as of September 30, 2003. At September 30, 2003, approximately $3 million of the restructuring costs had been paid. The plan will essentially be completed at the end of 2003. 7. Income Taxes Income taxes on earnings from continuing operations for the third quarter and nine months periods of 2003 were $147 million and $448 million, respectively, compared with $68 million and $203 million for the comparable periods of 2002. The effective income tax rate for the third quarter and nine months periods of 2003 was 49 percent and 45 percent, respectively, compared with 41 percent and 46 percent for the comparable periods of 2002. The higher effective tax rate in the third quarter of 2003, as compared with the same period a year ago, is due primarily to currency-related adjustments in Thailand, which was partially offset by the effect of the mix of positive domestic and foreign earnings in 2003 compared to the mix of domestic losses and foreign earnings in 2002. Foreign earnings are generally taxed at higher rates. The lower effective tax rate for the nine months period of 2003, as compared with 2002, reflects the mix of positive domestic and foreign earnings in 2003 compared to the mix of domestic losses and foreign earnings in 2002, which was partially offset by the effect of currency-related adjustments in Thailand and tax adjustments related to the sale of affiliate investments in 2003. The Company plans to carryforward the 2002 net operating loss into 2003. 8. Earnings Per Share The following are reconciliations of the numerators and denominators of the basic and diluted earnings per share ("EPS") computations for earnings from continuing operations for the third quarters and nine months ended September 30, 2003 and 2002:
- -------------------------------------------------------------------------------- Earnings Shares Per Share Millions except per share amounts (Numerator) (Denominator) Amount - -------------------------------------------------------------------------------- Three months ended September 30, 2003 Earnings from continuing operations $ 152 258.5 Basic EPS $ 0.59 ========= Effect of dilutive securities Options and common stock equivalents 1.9 --------------------------- 152 260.4 $ 0.58 Distributions on subsidiary trust preferred securities (after-tax) 7 12.3 --------------------------- Diluted EPS $ 159 272.7 $ 0.58 ========= Three months ended September 30, 2002 Earnings from continuing operations $ 99 244.6 Basic EPS $ 0.41 ========= Effect of dilutive securities Options and common stock equivalents 0.6 --------------------------- Diluted EPS 99 245.2 $ 0.41 ========= Distributions on subsidiary trust preferred securities (after-tax) 7 12.3 --------------------------- Antidilutive $ 106 257.5 $ 0.41 - --------------------------------------------------------------------------------
-9- Not included in the computation of diluted EPS for the three months ended September 30, 2003 and 2002, were options outstanding to purchase approximately 8.8 million and 8 million shares, respectively, of common stock. These options were not included in the computation as the exercise prices were greater than average market prices of the common shares during the respective quarters.
- -------------------------------------------------------------------------------- Earnings Shares Per Share Millions except per share amounts (Numerator) (Denominator) Amount - -------------------------------------------------------------------------------- Nine months ended September 30, 2003 Earnings from continuing operations $ 538 258.2 Basic EPS $ 2.08 ========= Effect of dilutive securities Options and common stock equivalents 1.7 --------------------------- 538 259.9 $ 2.07 Distributions on subsidiary trust preferred securities (after-tax) 21 12.3 --------------------------- Diluted EPS $ 559 272.2 $ 2.05 ========= Nine months ended September 30, 2002 Earnings from continuing operations $234 244.5 Basic EPS $ 0.96 ========= Effect of dilutive securities Options and common stock equivalents 0.9 --------------------------- Diluted EPS 234 245.4 $ 0.96 ========= Distributions on subsidiary trust preferred securities (after-tax) 20 12.3 --------------------------- Antidilutive $ 254 257.7 $ 0.99 - --------------------------------------------------------------------------------
Not included in the computation of diluted EPS for the nine months ended September 30, 2003 and 2002, were options outstanding to purchase approximately 9 million and 5.8 million shares, respectively, of common stock. These options were not included in the computation as the exercise prices were greater than average market prices of the common shares during the respective periods. Basic and diluted earnings per common share for discontinued operations were as follows:
For the Three Months For the Nine Months Ended September 30, Ended September 30, - -------------------------------------------------------------------------------- Millions except per share amounts 2003 2002 2003 2002 - -------------------------------------------------------------------------------- Basic earnings per share of common stock: Discontinued operations: Earnings from discontinued operations $ - $ - $ 8 $ 1 Weighted average common shares outstanding 258.5 244.6 258.2 244.5 Earnings from discontinued operations $ - $ - 0.03 $ - Dilutive earnings per share of common stock: Discontinued operations: Earnings from discontinued operations $ - $ - $ 8 $ 1 Weighted average common shares outstanding 272.7 245.2 272.2 245.4 Earnings from discontinued operations $ - $ - $ 0.03 $ - - --------------------------------------------------------------------------------
-10- 9. Stock-Based Compensation Prior to 2003, the Company applied APB Opinion No. 25, "Accounting for Stock Issued to Employees," and related interpretations in accounting for stock-based compensation. Before 2003, stock-based compensation expense recognized in the Company's consolidated earnings included expenses related to the Company's various cash incentive plans that are paid to certain employees based upon defined measures of the Company's common stock price performance and total shareholder return. In addition, the amounts also included expenses related to the Company's Pure Resources, Inc. ("Pure") subsidiary, which had its own stock-based compensation plans. Under Opinion No. 25, stock-based employee compensation cost was not recognized in earnings when stock options granted had an exercise price equal to the market value of the underlying common stock on the date of grant. Effective January 1, 2003, the Company adopted the fair value recognition provisions of SFAS No. 123, "Accounting for Stock-Based Compensation," prospectively to all employee awards granted, modified, or settled after December 31, 2002. Therefore, the cost related to stock-based employee compensation included in the determination of net earnings for 2003 is less than that which would have been recognized if the fair value based method had been applied to all awards since the original effective date of SFAS No. 123. The following table illustrates the effect on net earnings and earnings per share if the fair value based method had been applied to all outstanding and unvested awards in each period:
For the Three Months For the Nine Months Ended September 30, Ended September 30, - -------------------------------------------------------------------------------- Millions except per share amounts 2003 2002 2003 2002 - -------------------------------------------------------------------------------- Net earnings As reported $ 152 $ 99 $ 463 $ 235 Add: Stock-based employee compensation expense included in reported net income, net of related tax effects and minority interests 4 7 10 15 Deduct: Total stock-based employee compensation expense determined under the fair value based method for all awards, net of related tax effects and minority interests (5) (13) (15) (32) ------------------------------------ Pro forma net earnings $ 151 $ 93 $ 458 $ 218 ==================================== Net earnings per share: Basic - as reported $ 0.59 $ 0.41 $ 1.79 $ 0.96 Basic - pro forma $ 0.58 $ 0.38 $ 1.78 $ 0.89 Diluted - as reported $ 0.58 $ 0.41 $ 1.78 $ 0.96 Diluted - pro forma $ 0.58 $ 0.38 $ 1.76 $ 0.89
10. Comprehensive Income The Company's comprehensive income was:
For the Three Months For the Nine Months Ended September 30, Ended September 30, - -------------------------------------------------------------------------------- Millions of dollars 2003 2002 2003 2002 - -------------------------------------------------------------------------------- Net earnings $ 152 $ 99 $ 463 $ 235 Change in unrealized holding gain on investments (a) 8 - 8 - Change in unrealized gain (loss) on hedging instruments (b) 17 (26) 14 (35) Reclassification adjustment for settled hedging contracts (c) 5 - 16 (1) Unrealized pension liability adjustments (d) (21) - (21) - Unrealized foreign currency translation adjustments 2 (55) 116 (23) - -------------------------------------------------------------------------------- Total comprehensive income $ 163 $ 18 $ 596 $ 176 ================================================================================ (a) Net of tax effect of: 5 - 5 - (b) Net of tax effect of: 10 (15) 8 (21) (c) Net of tax effect of: 3 - 9 - (d) Net of tax effect of: 12 - 12 -
-11- 11. Cash and Cash Equivalents
At September 30, At December 31, ------------------------------------ Millions of dollars 2003 2002 - -------------------------------------------------------------------------------- Cash $ 240 $ 58 Time deposits 130 110 Marketable securities 115 - - -------------------------------------------------------------------------------- Cash and cash equivalents $ 485 $ 168 ================================================================================
The marketable securities at September 30, 2003 reflect the Company's short-term investment in a money market fund which invests in U.S. Treasury and other U.S. government agency obligations plus high quality bonds and commercial paper obligations of domestic corporations. The fund is rated "AAA" by Moody's Investors Service, Inc. and Standard & Poor's Ratings Services. 12. Assets Held for Sale The Company initiated a divestiture program in June 2003 that will involve approximately 100 fields in the Gulf of Mexico shelf and onshore, including associated pipelines. In the third quarter of 2003, the Company reached an agreement with Forest Oil Corporation ("Forest") for the sale of 70 properties. The sale of the majority of the 70 properties to Forest was completed in the fourth quarter of 2003 (see note 21). The Company expects to sell the rest of the properties by year-end. The Company has marked the assets to market at September 30, 2003, and does not anticipate material gains or losses upon the closing of the sales in the fourth quarter of 2003. The Company's Unocal North Sumatra Geothermal, Ltd. subsidiary has agreed to sell its rights and interest in the Sarulla geothermal project on the island of Sumatra, Indonesia to the Indonesian state electricity company. The anticipated sales price is $60 million. The transaction is expected to close in the fourth quarter of 2003, and the Company expects to record an after-tax gain of approximately $15 million on the transaction. The Company is in the process of selling its interests in the Trans-Andean oil pipeline, which transports crude oil from Argentina to Chile. The anticipated sales price is approximately $38 million. The transaction is expected to close early 2004, and the Company recorded a pre-tax impairment on the transaction of approximately $5 million in the third quarter of 2003. Details of the assets and liabilities for the assets classified as held for sale, as of September 30, 2003, are presented below:
Millions of dollars U.S. Lower 48 Midstream Geothermal Total - -------------------------------------------------------------------------------- Assets Properties - net $ 305 $ 6 $ 26 $ 337 Other assets 6 38 - 44 - -------------------------------------------------------------------------------- Total assets $ 311 $ 44 $ 26 $ 381 ================================================================================ Liabilities Accrued abandonment, restoration and environmental liabilities $ 90 $ - $ - $ 90 Other deferred credits and liabilities 7 - - 7 - -------------------------------------------------------------------------------- Total liabilities $ 97 $ - $ - $ 97 ================================================================================
-12- 13. Postemployment Benefit Plans The Company has numerous plans worldwide that provide eligible employees with retirement benefits. The Company also has medical plans that provide health care benefits for eligible employees and many of its retired employees. The Company's 2003 restructuring plan and the sale of producing properties in the Gulf of Mexico region resulted in the termination of a significant number of employees (see note 6). As a result, the Company recognized $5 million in curtailment costs related to its Qualified Retirement and Post Retirement Welfare plans covering current and former U.S. payroll employees. This charge is reflected as a component of administrative and general expense in the consolidated income statement. As a result of these terminations the Company was required to remeasure these postretirement benefit obligations as of September 30, 2003 and the cost of these plans for the full year 2003. In the third quarter of 2003 the Company recognized an additional $25 million in minimum pension liability as a result of the remeasurement of the obligations and assets of the Qualified Retirement Plan at September 30, 2003. The recognition of this additional liability resulted in an $8 million reduction in the intangible asset for unrecognized prior years' service costs and a pre-tax charge of $33 million ($21 million after-tax) to the other comprehensive income component of stockholders' equity. The assumed rates to measure the benefit obligations, expected returns on assets and expense for the Qualified Retirement and Post Retirement Welfare plans were:
Pension Benefits Other Benefits - -------------------------------------------------------------------------------- 1st-3rd Qtr. 4th Qtr. 1st-3rd Qtr. 4th Qtr. Rate assumptions 2003 2003 2003 2003 - -------------------------------------------------------------------------------- Discount rates 6.75% 6.00% 6.75% 6.00% Rates of salary increases 5.00% 5.00% 5.00% 5.00% Expected returns on plan assets 8.50% 8.50% N/A N/A
The remeasurement will not have a material impact on pension related expenses for the full year 2003 as the increase in the interest cost component triggered by utilizing a lower discount rate at September 30 was offset by lower service cost as a result of the curtailments. 14. Long Term Debt and Credit Agreements During the first nine months of 2003, the Company's consolidated debt, including the current portion, increased by $109 million. The Company retired $89 million in 9.25% debentures and paid down $11 million of medium-term notes which matured. The Company also repurchased $15 million of the $200 million outstanding balance in 6.375% notes due in 2004, $10 million of the $350 million outstanding balance in 7.35% notes due in 2009 and repaid $20 million of 6.20% Industrial Development Revenue Bonds. In 1999, the Company contributed fixed-price overriding royalty interests from its working interest shares in certain oil and gas producing properties in the Gulf of Mexico to Spirit LP. In exchange for its overriding royalty contributions, valued at $304 million, the Company received an initial general partnership interest in Spirit LP of approximately 55 percent. An unaffiliated investor contributed $250 million in cash to the partnership in exchange for an initial limited partnership interest of approximately 45 percent. In June, 2003 the Company entered into an agreement to pay the limited partner for its minority interest in Spirit LP, the amount of which was $252 million. In July, 2003 the agreement was executed and the payment was made. In the third quarter of 2003, FASB Interpretation No. 46 would have required the Company to consolidate the limited partner, an unaffiliated investor, which would have resulted in a reclassification of $242 million of minority interests to long-term debt. -13- These decreases in debt and other financings were partially offset by $154 million drawn under the Overseas Private Investment Corporation ("OPIC") Financing Agreement for the first phase of the West Seno project in Indonesia. The Company and its co-venturer completed financing arrangements for a portion of the total costs of the project through two loans arranged with OPIC. One loan is for $300 million and covers the first phase, and the other loan is for $50 million and is for the second phase. The second phase loan will be subject to further due diligence by the lender. The initial draw down of $79 million in April 2003 has a floating rate that is adjusted weekly, which as of September 30, 2003 was set at 1.06%. The remaining $75 million drawn down is fixed at a rate of 2.41%. Effective in the third quarter of 2003, FASB Interpretation No. 46 (see note 2 for further details) required the Company to consolidate assets and liabilities and results of operations of Dayabumi Salak Pratama, Ltd. ("DSPL"), resulting in the recording of an additional $78 million as long-term debt on the consolidated balance sheet at September 30, 2003. At September 30, 2003, the 3-year $295 million Canadian dollar-denominated non-revolving credit facility was unchanged; however due to increasing strength of the Canadian dollar, borrowings under the credit facility translated to $216 million, using applicable foreign exchange rates, or a $30 million increase from year-end 2002. 15. Variable Interest Entities DSPL is a variable interest entity formed for the purpose of building and operating a geothermal energy fueled power generating facility in Indonesia. Under a long-term electricity sales contract, DSPL provides power to the Indonesian state-owned electricity company, PT. PLN (Persero) ("PLN"). Unocal Geothermal of Indonesia, Ltd. ("UGI") owns a 50 percent interest in DSPL and is under contract to administer DSPL operations. DSPL has no employees of its own. DSPL had loans and notes payable totaling $78 million at September 30, 2003. Neither UGI nor the Company has guaranteed DSPL's debt obligations, which are non-recourse. Effective in the third quarter of 2003, FASB Interpretation No. 46 (see note 2 for further details) required the Company to consolidate DSPL, resulting in the reporting of an additional $78 million as long-term debt on the consolidated balance sheet at September 30, 2003. 16. Accrued Abandonment, Restoration and Environmental Liabilities Effective January 1, 2003, the Company adopted SFAS No. 143 which increased its accrued abandonment and restoration liabilities by $268 million (see note 2 for further detail). At January 1, 2003 and September 30, 2003, the Company had accrued $758 million and $791 million, respectively, in estimated abandonment and restoration costs as liabilities. The increase in the liability account from January 1, 2003 was due to accrued pre-tax accretion expense of $33 million. Abandonment liability settlements totaled $13 million during the first nine months of 2003 and were offset by $13 million in new abandonment liabilities recorded during the period. There were no material revisions to existing abandonment and restoration liabilities during the first nine months of 2003. The Company's total accrued abandonment and restoration liabilities of $791 million at September 30, 2003, include $90 million in abandonment liabilities associated with assets held for sale (see note 12 for further detail). The September 30, 2003 liability amount represented approximately one-half of the Company's determinable abandonment and restoration costs adjusted for inflation. The Company's reserve for environmental remediation obligations at September 30, 2003 totaled $265 million, of which $144 million was included in current liabilities. This compared with $245 million at December 31, 2002, of which $113 million was included in current liabilities. -14- 17. Commitments and Contingencies The Company has contingent liabilities with respect to material existing or potential claims, lawsuits and other proceedings, including those involving environmental, tax, guarantees and other matters, certain of which are discussed more specifically below. The Company accrues liabilities when it is probable that future costs will be incurred and such costs can be reasonably estimated. Such accruals are based on developments to date, the Company's estimates of the outcomes of these matters and its experience in contesting, litigating and settling other matters. As the scope of the liabilities becomes better defined, there will be changes in the estimates of future costs, which could have a material effect on the Company's future results of operations and financial condition or liquidity. Environmental matters The Company continues to move forward to address environmental issues for which it is responsible. The Company, in cooperation with regulatory agencies and others, follows procedures that it has established to identify and cleanup contamination associated with its past operations. The Company is subject to loss contingencies pursuant to federal, state, local and foreign environmental laws and regulations. These include existing and possible future obligations to investigate the effects of the release or disposal of certain petroleum, chemical and mineral substances at various sites; to remediate or restore these sites; to compensate others for damage to property and natural resources, for remediation and restoration costs and for personal injuries; and to pay civil penalties and, in some cases, criminal penalties and punitive damages. These obligations relate to sites owned by the Company or others and are associated with past and present operations, including sites at which the Company has been identified as a potentially responsible party ("PRP") under the federal Superfund laws and comparable state laws. Liabilities are accrued when it is probable that future costs will be incurred and such costs can be reasonably estimated. However, in many cases, investigations are not yet at a stage where the Company is able to determine whether it is liable or, even if liability is determined to be probable, to quantify the liability or estimate a range of possible exposure. In such cases, the amounts of the Company's liabilities are indeterminate due to the potentially large number of claimants for any given site or exposure, the unknown magnitude of possible contamination, the imprecise and conflicting engineering evaluations and estimates of proper clean-up methods and costs, the unknown timing and extent of the corrective actions that may be required, the uncertainty attendant to the possible award of punitive damages, the recent judicial recognition of new causes of action, the present state of the law, which often imposes joint and several and retroactive liabilities on PRPs, the fact that the Company is usually just one of a number of companies identified as a PRP, or other reasons. As disclosed in note 16, at September 30, 2003, the Company had accrued $265 million for estimated future environmental assessment and remediation costs at various sites where liabilities for such costs are probable and reasonably estimable. The Company may also incur additional liabilities in the future at sites where remediation liabilities are probable but future environmental costs are not presently reasonably estimable because the sites have not been assessed or the assessments have not advanced to the stage where costs are reasonably estimable. At those sites where investigations or feasibility studies have advanced to the stage of analyzing feasible alternative remedies and/or ranges of costs, the Company estimates that it could incur possible additional remediation costs aggregating approximately $210 million. The amount of such possible additional costs reflects the aggregate of the high ends of the ranges of costs of feasible alternatives identified by the Company for those sites with respect to which investigation or feasibility studies have advanced to the stage of analyzing such alternatives. However, such estimated possible additional costs are not an estimate of the total remediation costs beyond the amounts reserved, because there are sites where the Company is not yet in a position to estimate all, or in some cases any, possible additional costs. Both the amounts reserved and estimates of possible additional costs may change in the near term, and in some cases could change substantially, as additional information becomes available regarding the nature and extent of site contamination, required or agreed-upon remediation methods and other actions by government agencies and private parties. -15- The accrued costs and the possible additional costs are shown below for four categories of sites:
At September 30, 2003 ---------------------------- Possible Additional Millions of dollars Reserve Costs - -------------------------------------------------------------------------------- Superfund and similar sites $ 16 $ 15 Active Company facilities 32 30 Company facilities sold with retained liabilities and former Company-operated sites 99 80 Inactive or closed Company facilities 118 85 - -------------------------------------------------------------------------------- Total $ 265 $ 210 ================================================================================
The time frames over which the amounts included in the reserve may be paid extend from the near term to several years into the future. The sites included in the above categories are in various stages of investigation and remediation; therefore, the related payments against the existing reserve will be made in future periods. Also, some of the work is dependent upon reaching agreements with regulatory agencies and/or other third parties on the scope of remediation work to be performed, who will perform the work, the timing of the work, who will pay for the work and other factors that may have an impact on the timing of the payments for amounts included in the reserve. For some sites, the remediation work will be performed by other parties, such as the current owners of the sites, and the Company has a contractual agreement to pay a share of the remediation costs. For these sites, the Company generally has less control over the timing of the work and consequently the timing of the associated payments. Based on available information, the Company estimates that the majority of the amounts included in the reserve will be paid within the next three to five years. At the sites where the Company has contractual agreements to share remediation costs with third parties, the reserve reflects the Company's estimated shares of those costs. In many of the oil and gas sites, remediation cost sharing is included in joint venture agreements that were made with third parties during the original operation of the sites. In many cases where the Company sold facilities or a business to a third party, sharing of remediation costs for those sites may be included in the sales agreement. Contamination at the sites of the "Superfund and similar sites" category was the result of the disposal of substances at these sites by one or more PRPs. Contamination of these sites could be from many sources, of which the Company may be one. The Company has been notified that it is a PRP at the sites included in this category. At the sites where the Company has not denied liability, the Company's contribution to the contamination at these sites was primarily from operations identified below. The "Active Company facilities" category includes oil and gas fields and mining operations. The oil and gas sites are primarily contaminated with crude oil, oil field waste and other petroleum hydrocarbons. Contamination at the active mining sites was principally the result of the impact of mined material on the groundwater and/or surface water at these sites. The "Company facilities sold with retained liabilities and former Company-operated sites" and "Inactive or closed Company facilities" categories include former Company refineries, transportation and distribution facilities and service stations. The required remediation of these sites is mainly for petroleum hydrocarbon contamination as the result of leaking tanks, pipelines or other equipment or impoundments that were used in these operations. Also, included in these categories are former oil and gas fields that the Company no longer operates. In most cases, these sites are contaminated with crude oil, oil field waste and other petroleum hydrocarbons. Contamination at other sites in these categories of sites was the result of former industrial chemical and polymers manufacturing and distribution facilities, agricultural chemical retail businesses and ferromolybdenum production operations. -16- Superfund and similar sites - Included in this category of sites are: o The McColl site in Fullerton, California o The Operating Industries site in Monterey Park, California o The Casmalia Waste site in Casmalia, California At September 30, 2003, Unocal had received notifications from the U.S. Environmental Protection Agency ("EPA") that the Company may be a PRP at 22 sites and may share certain liabilities at these sites. Of the total, four sites are under investigation and/or litigation and the Company's potential liability is not presently determinable and for one site, the Company has denied responsibility. At one site the Company's potential liability appears to be de minimis. Of the remaining 16 sites, where the Company has concluded that liability is probable and to the extent costs can be reasonably estimated, a reserve of $12 million has been established for future remediation and settlement costs. Various state agencies and private parties had identified 18 other similar PRP sites. Four sites are under investigation and/or litigation and the Company's potential liability is not presently determinable and at three sites the Company's potential liability appears to be de minimis. Where the Company has concluded that liability is probable and to the extent costs can be reasonably estimated at the remaining 11 sites, a reserve of $4 million has been established for future remediation and settlement costs. The sites discussed above exclude 125 sites where the Company's liability has been settled, or where the Company has no evidence of liability and there has been no further indication of liability by government agencies or third parties for at least a 12-month period. The Company does not consider the number of sites for which it has been named a PRP as a relevant measure of liability. Although the liability of a PRP is generally joint and several, the Company is usually just one of numerous companies designated as a PRP. The Company's ultimate share of the remediation costs at those sites often is not determinable due to many unknown factors. The solvency of other responsible parties and disputes regarding responsibilities may also impact the Company's ultimate costs. Active Company facilities - Included in this category are: o The Molycorp molybdenum mine in Questa, New Mexico o The Molycorp lanthanide facility in Mountain Pass, California o Alaska oil and gas properties The Company has a reserve of $32 million for estimated future costs of remedial orders, corrective actions and other investigation, remediation and monitoring obligations at certain operating facilities and producing oil and gas fields. The Company recorded provisions of $8 million during the first nine months of 2003 for the "Active Company facilities" category of sites. The provisions were primarily for the remedial investigation and feasibility study (RI/FS) being performed at a molybdenum mine located in Questa, New Mexico, that is owned by the Company's Molycorp, Inc. ("Molycorp") subsidiary. Molycorp has been working closely with the U.S. Environmental Protection Agency and the State of New Mexico in conducting the RI/FS at the mine during the year. The RI/FS is being performed to determine if past mining operations have had an adverse impact on the environment. Numerous additions and changes to the RI/FS scope have been required by the agencies, which will require a higher level of effort than originally projected. The Company made payments of $9 million for this category of sites in the first nine months of 2003. Company facilities sold with retained liabilities and former Company-operated sites - Company facilities sold with retained liabilities include: o West Coast refining, marketing and transportation sites o Auto/truckstop facilities in various locations in the U.S. o Industrial chemical and polymer sites in the South, Midwest and California o Agricultural chemical sites in the West and Midwest. -17- In each sale, the Company retained a contractual remediation or indemnification obligation and is responsible only for certain environmental problems that resulted from operations prior to the sale. The reserve represents estimated future costs for remediation work: identified prior to the sale of these sites; included in negotiated agreements with the buyers of these sites where the Company retained certain levels of remediation liabilities; and/or identified in subsequent claims made by buyers of the properties. Former Company-operated sites include service stations, distribution facilities and oil and gas fields that were previously operated but not owned by the Company. The Company has an aggregate reserve of $99 million for this group of sites. During the first nine months of 2003, provisions of $27 million for the "Company facilities sold with retained liabilities and former Company-operated sites" category were recorded. These provisions included the estimated cleanup costs for oil fields located in Michigan and California that were formerly operated by the Company. The estimated costs are based on assessments recently performed at the sites, higher than anticipated volumes of contaminated soil at existing sites and higher remediation costs for soil excavation and disposal than originally anticipated. The provisions for this category of sites were also the result of revised remediation cost estimates that were identified during the first and second quarters of 2003 for former service station sites. Payments of $32 million were made during the first nine months of 2003 for sites in this category. Inactive or closed Company facilities - The major sites in this category are: o The Guadalupe oil field on the central California coast o The Molycorp Washington and York facilities in Pennsylvania o The Beaumont Refinery in Texas. A reserve of $118 million has been established for these types of facilities. During the first nine months of 2003, the Company accrued $42 million related to sites in this category primarily for the Guadalupe oil field and for remediation projects at the Beaumont Refinery. For the Guadalupe oil field site, it was determined that contaminated soil excavated from the site will probably be taken to an offsite landfill for disposal. The soil is contaminated with diluent, a kerosene-like additive used in the field's former operations. Previously, the Company had planned to remediate the soil on-site; however, a preliminary draft report for the ecological risk study being conducted indicates that on-site remediation is not viable. The provisions recorded for the site include the costs for the offsite disposal alternative. The provisions recorded for the Guadalupe oil field also include estimated costs for remediation work that is ongoing at the site. This work includes groundwater monitoring, operation and maintenance of remedial systems, restoration, site assessment and regulatory agency oversight and permitting procedures. The provisions for these costs are based on data from various studies and assessments that have been completed for the site in conjunction with data provided by the project management system the Company has in place. A provision was also recorded for the Company's former Beaumont, Texas refinery. The Company has been working with the Texas Commission on Environmental Quality ("TCEQ") to develop plans for closing impoundments used in the site's former operations and for other remediation projects. In the first nine months of 2003, the Company recorded a provision for the revised estimated costs of the impoundment closure plan based on the TCEQ initial draft permit that was issued for the site. Payments of $11 million were made during the first nine months of 2003 for sites in this category. The Company is subject to federal, state and local environmental laws and regulations, including the Comprehensive Environmental Response, Compensation and Liability Act of 1980 ("CERCLA"), as amended, the Resource Conservation and Recovery Act ("RCRA") and laws governing low level radioactive materials. Under these laws, the Company is subject to existing and/or possible obligations to remove or mitigate the environmental effects of the disposal or release of certain chemical, petroleum and radioactive substances at various sites. Corrective investigations and actions pursuant to RCRA and other federal, state and local environmental laws are being performed at the Company's facility in Beaumont, Texas, a former agricultural chemical facility in Corcoran, California, and Molycorp's facility in Washington, Pennsylvania. In addition, Molycorp is required to decommission its Washington and York facilities in Pennsylvania pursuant to the terms of their respective radioactive source materials licenses and decommissioning plans. -18- The Company also must provide financial assurance for future closure and post-closure costs of its RCRA-permitted facilities and for decommissioning costs at facilities that are under radioactive source materials licenses. Pursuant to a 1998 settlement agreement between the Company and the State of California (and the subsequent stipulated judgment entered by the Superior Court), the Company must provide financial assurance for anticipated costs of remediation activities at its inactive Guadalupe oil field. Also, pursuant to a 1995 settlement agreement between Molycorp and the California Department of Toxic Substances Control (and subsequent final judgment entered by the Superior Court), the Company must provide financial assurance for anticipated costs of disposing of certain wastes, as well as closing facilities associated with the handling of those wastes, at Molycorp's Mountain Pass, California, facility. At September 30, 2003, amounts in the remediation reserve for these facilities totaled $121 million, as included in the previously discussed "Active Company facilities" and "Inactive or closed Company facilities" categories. At those sites where investigations or feasibility studies have advanced to the stage of analyzing alternative remedies and/or ranges of costs, the Company estimates that it could incur possible additional remediation costs aggregating approximately $55 million. Although any possible additional costs for these sites are likely to be incurred at different times and over a period of many years, the Company believes that these obligations could have a material adverse effect on the Company's results of operations but are not expected to be material to the Company's consolidated financial condition or liquidity. The total environmental remediation reserve recorded on the consolidated balance sheet represents the Company's estimates of assessment and remediation costs based on currently available facts, existing technology and presently enacted laws and regulations. The remediation cost estimates, in many cases, are based on plans recommended to the regulatory agencies for approval and are subject to future revisions. The ultimate costs to be incurred could exceed the total amounts reserved. The reserve will be adjusted as additional information becomes available regarding the nature and extent of site contamination, required or agreed-upon remediation methods and other actions by government agencies and private parties. Therefore, amounts reserved may change substantially in the near term. The Company maintains insurance coverage intended to reimburse the cost of damages and remediation related to environmental contamination resulting from sudden and accidental incidents under current operations. The purchased coverages contain specified and varying levels of deductibles and payment limits. Although certain of the Company's contingent legal exposures enumerated above are uninsurable either due to insurance policy limitations, public policy or market conditions, management believes that its current insurance program significantly reduces the possibility of an incident causing a material adverse financial impact to the Company. -19- Certain Litigation and Claims City of Santa Monica MTBE Lawsuit: In 2000, the City of Santa Monica, California (the "City") sued Shell Oil Company and other oil companies, including the Company, for contamination with methyl tertiary butyl ether ("MTBE") and a related chemical, tertiary butyl alcohol ("TBA"), of water pumped from the City's Charnock wellfield (City of Santa Monica v. Shell Oil Company et al. California Superior Court, Orange County, Case No. 01CC04331). The City alleges that releases from sites owned by Shell, ChevronTexaco Corporation and ExxonMobil Corporation caused the wellfield to be shut down, that releases from sites owned by Unocal subsequently impacted the wellfield. The City also alleges Unocal is liable under a products liability theory for gasoline it manufactured or sold that was ultimately distributed to area facilities operated by others. The Company is also subject to potential contractual liability for contamination from former facilities related to our gasoline marketing business sold in 1997. In 2001, Shell filed a cross-complaint against the Company and other oil companies, seeking the recovery of the funds it has expended to respond to the contamination. Several of the defendants other than the Company have entered into settlement agreements with the City, which are subject to court approval. The Company's current analysis does not indicate any such liabilities are likely to be significant. Based on a rigorous technical analysis of the data, the Company believes it has strong defenses to the allegations in the complaint applicable to both its former operations and facilities and the product liability claims, including the lack of evidence that its former service stations or activities are responsible for any contamination that has reached or threatens the wellfield. Subject to a lifting of a current stay of discovery due to ongoing settlement discussions among the parties the Company intends to request completion of limited discovery previously stayed that may support filing of appropriate motions for summary adjudication on the City's most significant claims. For several years prior to the City's suit, the EPA and the California Regional Water Quality Control Board have asserted jurisdiction over contamination of groundwater potentially affecting the wellfield, and these agencies have issued a number of orders under RCRA and state law to the Shell defendants and the other defendant oil companies, including the Company, with respect to both investigation of individual facilities and regional contamination, and requiring replacement of water lost to the City, which Shell is currently providing. In January 2003, the EPA Regional Administrator for Region IX wrote to the settling parties advising that it intended to issue a unilateral order to all parties whose releases have been demonstrated to contribute to contamination in the Charnock Sub-Basin ordering cleanup of MTBE and TBA "hot spots," unless a settlement in principle among all concerned parties was reached by June 30, 2003. The Company has submitted to these agencies several technical analyses, which it believes demonstrate that its sites are not a part of any regional contamination problem, but, rather, present, at the most, localized issues which the Company, under agency oversight, has been successfully resolving. The Company met with senior EPA and Water Board Officials in May 2003 to discuss these issues, and the EPA has so far taken no action on its January 2003 letter, but continues to assert potential enforcement options if overall settlements are not reached. Agrium Litigation: In June 2002, a lawsuit was filed against the Company by Agrium Inc., a Canadian corporation, and Agrium U.S. Inc., its U. S. subsidiary, in the Superior Court of the State of California for the County of Los Angeles (Agrium U.S. Inc. and Agrium Inc. v. Union Oil Company of California, Case No. BC275407) (the "Agrium Claim"). Simultaneously, the Company filed suit against the Agrium entities ("Agrium") in the U.S. District Court for the Central District of California (Union Oil Company of California v. Agrium, Inc., Case No. 02-04518 NM) (the "Company Claim"). The Company subsequently removed the Agrium Claim to the U.S. District Court for the Central District of California (Case No. 02-04769 NM). The federal court has since remanded the Agrium Claim to the California Superior Court. In addition, the Company has initiated arbitration concerning the Gas Purchase and Sale Agreement ("GPSA") between the Company and Agrium U.S. Inc. (AAA Case No. 70 198 00539 02) (the "Arbitration"). -20- The Agrium Claim alleges numerous causes of action relating to Agrium's purchase from the Company of a nitrogen-based fertilizer plant on the Kenai Peninsula, Alaska, in September 2000. The primary allegations involve the Company's obligation to supply natural gas to the plant pursuant to the GPSA. Agrium alleges that the Company misrepresented the amount of natural gas reserves available for sale to the plant as of the closing of the transaction and that the Company has failed to develop additional natural gas reserves for sale to the plant. Agrium also alleges that the Company misrepresented the condition of the general effluent sewer at the plant and made misrepresentations regarding other environmental matters. Agrium seeks damages in an unspecified amount for breach of such representations and warranties, as well as for alleged misconduct by the Company in operating and managing certain oil and gas leases and other facilities. Agrium also seeks declaratory relief concerning the base price of gas under the GPSA, as well as for the calculation of payments under a "Retained Earnout" covenant that entitles the Company to certain contingent payments based on the price of ammonia subsequent to the September 2000 closing. The complaint includes demands for punitive damages and attorneys' fees. In September 2002, Agrium amended its complaint to add allegations that the Company breached certain conditions of the September 2000 closing, breached certain indemnification obligations, and violated the pertinent health and safety code. Agrium also asked for recission of the sale of the fertilizer plant, in addition, or as an alternative, to money damages. In the Company Claim, the Company seeks declaratory relief in its favor against the allegations of Agrium set forth above and for judgment on the Retained Earnout in the amount of $17 million plus interest accrued subsequent to May 2002. Unocal is also seeking over $600,000 in reliability bonuses due under the GSA and reimbursement of over $5 million in royalties paid to the State of Alaska. The GPSA contains a contractual limit on liquidated damages of $25 million per year, not to exceed a total of $50 million over the life of the agreement. In addition, the agreement for the sale of the plant (the "PSA") contains a limit on damages of $50 million. The Company believes it has a meritorious defense to each of the Agrium claims, but that in any event its exposure to damages for all disputes is limited by the agreements. Agrium alleges that it is entitled to recover damages in excess of those amounts. On July 16, 2003, the court approved an agreed stipulation between the parties to submit all issues under the GPSA to arbitration. The arbitration proceedings are scheduled to commence May 24, 2004. Discovery is now proceeding. Bangladesh Moulavi Bazar #1 Claims: In July 2002, the Company's subsidiary Unocal Bangladesh Blocks Thirteen and Fourteen, Ltd. ("Unocal Blocks 13 and 14 Ltd.") received a letter from the Bangladesh Oil, Gas & Mineral Corporation ("Petrobangla") claiming, on behalf of the Bangladesh government and Petrobangla, compensation allegedly due in the amount of $685 million for 246 BCF of recoverable natural gas allegedly "lost and damaged" in a 1997 blowout and ensuing fire during the drilling by Occidental Petroleum Corporation (known at that time in Bangladesh as Occidental of Bangladesh Ltd.) ("OBL"), as operator, of the Moulavi Bazar #1 ("MB #1") exploration well on the Blocks 13 and 14 PSC area in Northeast Bangladesh. The Company and OBL believe that the claim vastly overstates the amount of recoverable gas involved in the blowout. Consistent with worldwide industry contracting practice, there was no provision in the PSC for compensating the Bangladesh government or Petrobangla for resources lost during the contractors' operations. Even if some form of compensation were due, the Company and OBL believe that settlement compensation for the blowout was fully addressed in a 1998 Supplemental Agreement to the PSC (the "Supplemental Agreement"), which, among other matters, waived OBL's then 50-percent contractor's share (as well as the then 50-percent contractor's share held by the Company's Unocal Bangladesh, Ltd., subsidiary ("Unocal Bangladesh")) of entitlement to the recovery of costs incurred in the blowout, waived their right to invoke force majeure in connection with the blowout, and reduced by five percentage points their contractors' profit share (with a concomitant increase in Petrobangla's profit share) of future production from the sands encountered by the MB #1 well to a drill depth of 840 meters or, if the blowout sand reservoir were not deemed commercial, from other commercial fields in the Moulavi Bazar "ring-fenced" area of Block 14. Consequently, the Company and OBL consider the matter closed and Unocal Blocks 13 and 14 Ltd. has advised Petrobangla that no additional compensation is warranted. -21- By Writ Petition Affidavit dated March 24, 2003, a concerned citizen filed suit in the Bangladesh lower court (Alam v. Bangladesh, Petrobangla, Department of Environment, and Unocal Bangladesh, Ltd., Supreme Court of Bangladesh, High Court Division, Writ Petition No. 2461 of 2003) on the basis of the MB #1 blowout. The Company was notified of the suit on May 26, 2003 when it received the court's order to show cause why the Supplemental Agreement should not be declared illegal and cancelled on account of its having been executed without lawful authority, and why Unocal Bangladesh should not be directed to stop exploration until it compensates for the MB#1 blowout. No hearing is currently scheduled on the matter, and the Company believes the action is not well founded. Nuevo Energy Claim: In March 2003, the Company received a letter from Nuevo Energy Company regarding a contingent payment for the year 2002 owed by Nuevo to the Company under the terms of the 1996 Asset Purchase Agreement pursuant to which Nuevo purchased substantially all of the Company's operating California oil and gas properties. Notwithstanding that Nuevo had notified the Company in January 2003 of its estimate of the payment for 2002, Nuevo now claims that the long-standing calculation methodology for this payment was incorrect, that no payment should be due for 2002, and that the payment made for 2001 should be refunded. The Company disputes Nuevo's new position. The current disputed cash exposure to the Company is $27 million. On June 30, 2003, Nuevo filed suit against Unocal in the U.S. District Court for the Central District of California, Case No. 03-4664 (RCx). Nuevo seeks $10.8 million, the amount Nuevo alleges it paid Unocal in error. Nuevo also seeks a declaratory judgment regarding its right to take deductions in calculating the contingent payment in the future. Unocal has counterclaimed, seeking in excess of $16 million for amounts currently owed under the contingent payment agreement and for a declaratory judgment regarding the rights and relations of Unocal and Nuevo under that agreement. In view of the inherent difficulty of predicting the outcome of legal matters, the Company cannot state with confidence what the eventual outcome of the four preceding matters will be. However, based on current knowledge, none of the preceding matters is presently expected to have a material adverse effect on the Company's consolidated financial condition or liquidity, but each of them could have a material adverse effect on the Company's results of operations for the accounting period or periods in which one or more of them might be resolved adversely. Tax matters The Company believes it has adequately provided in its accounts for tax items and issues not yet resolved. Several prior material tax issues are unresolved. Resolution of these tax issues impact not only the year in which the items arose, but also the Company's tax situation in other tax years. With respect to 1979-1984 taxable years, all issues raised for these years have now been settled, with the exception of the effect of the carryback of a 1993 net operating loss ("NOL") to tax year 1984 and resultant credit adjustments. The 1985-1990 taxable years are before the Appeals division of the Internal Revenue Service. All issues raised with respect to those years have now been settled, with the exception of the effect of the 1993 NOL carryback and resultant adjustments. The Joint Committee on Taxation of the U.S. Congress has reviewed the settled issues with respect to 1979-1990 taxable years and no additional issues have been raised. While all tax issues for the 1979-1990 taxable years have been agreed and reviewed by the Joint Committee, these taxable years will remain open due to the 1993 NOL carryback. The 1993 NOL results from certain specified liability losses, which occurred during 1993, and which resulted in a tax refund of $73 million. Consequently, these tax years will remain open until the specified liability loss, which gave rise to the 1993 NOL, is finally determined by the Internal Revenue Service and is either agreed to with the IRS or otherwise concluded in the Tax Court proceeding. In 1999, the United States Tax Court granted Unocal's motion to amend the pleadings in its Tax Court cases to place the 1993 NOL carryback in issue. The 1991-1994 taxable years are now before the Appeals division of the Internal Revenue Service. The 1995-1997 taxable years are before the Appeals division of the Internal Revenue Service. The 1998-2001 taxable years are now under examination by the Internal Revenue Service. -22- Guarantees Related to Assets or Obligations of Third Parties The Company has agreed to indemnify certain third parties for particular future remediation costs that may be incurred for properties held by these parties. The guarantees were established when the Company either leased property from or sold property to these third parties. The properties may or may not have been contaminated by various Company operations. Where it has been or will be determined that the Company is responsible for contamination, the guarantees require the Company to pay the costs to remediate the sites to specified cleanup levels or to levels that will be determined in the future. The maximum potential amount of future payments that the Company could be required to make under these guarantees is indeterminate primarily due to the following: the indefinite term of the majority of these guarantees; the unknown extent of possible contamination; uncertainties related to the timing of the remediation work; possible changes in laws governing the remediation process; the unknown number of claims that may be made; changes in remediation technology; and the fact that most of these guarantees lack limitations on the maximum potential amount of future payments. The Company has accrued probable and reasonably estimable assessment and remediation costs for the locations covered under these guarantees. These amounts are included in the "Company facilities sold with retained liabilities and former Company-operated sites" category of the Company's reserve for environmental remediation obligations. At September 30, 2003, the reserve for this category totaled $99 million. For those sites where investigations or feasibility studies have advanced to the stage of analyzing feasible alternative remedies and/or ranges of costs, the Company estimates that it could incur possible additional remediation costs aggregating approximately $80 million. See the discussion elsewhere in this footnote for additional information regarding this category. The Company has guaranteed the debt of certain joint ventures accounted for by the equity method. The majority of this debt matures evenly through the year 2014. The maximum potential amount of future payments the Company could be required to make is approximately $20 million. In the ordinary course of business, the Company has agreed to indemnify cash deficiencies for certain domestic pipeline joint ventures, which the Company accounts for on the equity method. These guarantees are considered in the Company's analysis of overall risk. Since most of these agreements do not contain spending caps, it is not possible to quantify the amount of maximum payments that may be required. Nevertheless, the Company believes the payments would not have a material adverse impact on its financial condition or liquidity. -23- Financial Assurance for Unocal Obligations In the normal course of business, the Company has performance obligations which are secured, in whole or in part, by surety bonds or letters of credit. These obligations primarily cover self-insurance, site restoration, dismantlement and other programs where governmental organizations require such support. These surety bonds and letters of credit are issued by financial institutions and are required to be reimbursed by the Company if drawn upon. At September 30, 2003, the Company had obtained various surety bonds for approximately $196 million. These surety bonds included a bond for $83 million securing the Company's performance under a fixed price natural gas sales contract for the delivery of 72 billion cubic feet of gas over a ten-year period that began in January of 1999 and will end in December of 2008 and approximately $113 million in various other routine performance bonds held by local, city, state and federal agencies. The Company also had obtained approximately $46 million in standby letters of credit at September 30, 2003, of which $17 million represented additional collateral related to the aforementioned fixed price natural gas sales contract. The Company has entered into indemnification obligations in favor of the providers of these surety bonds and letters of credit. The Company has various other guarantees for approximately $553 million. Approximately $134 million of the $553 million in guarantees represent financial assurance given by the Company on behalf of its Molycorp subsidiary relating to permits covering operations and discharges from its Questa, New Mexico, molybdenum mine. The Company's financial assurance is for the completion of temporary closure plans (required only upon cessation of operations) and other obligations required under the terms of the permits. The costs associated with the financial assurance are based on estimations provided by agencies of the state of New Mexico. Guarantees for approximately $333 million of the $553 million would require the Company to obtain a surety bond or a letter of credit or establish a trust fund if its credit rating were to drop below investment grade--that is BBB- or Baa3 from Standard & Poor's Ratings Services and Moody's Investors Service, Inc., respectively. Approximately $165 million of the surety bonds, letters of credit and other guarantees that the Company is required to obtain or issue reflect obligations that are already included on the consolidated balance sheet in other current liabilities and other deferred credits. The surety bonds, letters of credit and other guarantees may also reflect some of the possible additional remediation liabilities discussed earlier in this note. Other matters The Company has a lease agreement relating to its Discoverer Spirit deepwater drillship, with a remaining term of approximately 24 months at September 30, 2003. The drillship has a current minimum daily rate of approximately $224,000. The future remaining minimum lease payment obligation was approximately $160 million at September 30, 2003. The Company also has other contingent liabilities with respect to litigation, claims and contractual agreements arising in the ordinary course of business. On the basis of management's assessment of the ultimate amount and timing of possible adverse outcomes and associated costs, none of such matters is presently expected to have a material adverse effect on the Company's consolidated financial condition, liquidity or results of operations. -24- 18. Financial Instruments and Commodity Hedging Fair values of debt and other long-term instruments - The estimated fair value of the Company's long-term debt at September 30, 2003, including the current portion, was approximately $3.49 billion. The fair value was based on the discounted amounts of future cash outflows using the rates offered to the Company for debt with similar remaining maturities. The estimated fair value of Unocal Capital Trust's 6 1/4 % convertible preferred securities was approximately $530 million at September 30, 2003. The fair value was based on the closing trading price of the preferred securities on September 30, 2003. Commodity hedging activities - The Company uses hydrocarbon derivatives to mitigate its overall exposure to fluctuations in hydrocarbon commodity prices. The Company recognized $1 million of gains due to ineffectiveness for cash flow and fair value hedges in the third quarter and $2 million in gains in the nine months period ended September 30, 2003. At September 30, 2003, the Company had approximately $19 million of after-tax deferred gains in accumulated other comprehensive income on the consolidated balance sheet related to cash flow hedges for future commodity sales for the period beginning October 2003 through December 2005. Essentially all of the after-tax gains are expected to be reclassified to the consolidated earnings statement during the next twelve months. Foreign currency contracts - At September 30, 2003, the Company had approximately $1 million of after-tax deferred gains in accumulated other comprehensive income on the consolidated balance sheet related to cash flow hedges for future foreign currency denominated payment obligations through December 2003. This entire amount is expected to be reclassified to the consolidated earnings statement during the next twelve months. Interest rate contracts - The Company enters into interest rate swap contracts to manage its debt with the objective of minimizing the volatility and magnitude of the Company's borrowing costs. The Company may also enter into interest rate option contracts to protect its interest rate positions, depending on market conditions. At September 30, 2003, the Company had approximately $23 million of after-tax deferred losses in accumulated other comprehensive income on the consolidated balance sheet related to cash flow hedges of interest rate exposures through September 2012. Of this amount, $3 million in after-tax losses are expected to be reclassified to the consolidated earnings statement during the next twelve months. Credit Risk - Financial instruments that potentially subject the Company to concentrations of credit risks primarily consist of temporary cash investments and trade receivables. The Company places its temporary cash investments with high credit quality financial institutions and, by policy, limits the amount of credit exposure to any one financial institution. The concentration of trade receivable credit risk is generally limited due to the Company's customers being spread across industries in several countries. The Company's management has established certain credit requirements that its customers must meet before sales credit is extended. The Company monitors the financial condition of its customers to help ensure collections and to minimize losses. -25- 19. Supplemental Condensed Consolidating Financial Information Unocal guarantees all the publicly held securities issued by its 100 percent-owned subsidiaries Unocal Capital Trust and Union Oil. Such guarantees are full and unconditional and no subsidiaries of Unocal or Union Oil guarantee these securities. The following tables present condensed consolidating financial information for (a) Unocal (Parent), (b) the Trust, (c) Union Oil (Parent) and (d) on a combined basis, the subsidiaries of Union Oil (non-guarantor subsidiaries). Virtually all of the Company's operations are conducted by Union Oil and its subsidiaries.
CONDENSED CONSOLIDATED EARNINGS STATEMENT Three months ended September 30, 2003 Unocal Non- Unocal Capital Union Oil Guarantor Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated - ----------------------------------------------------------------------------------------------------------------------------- Revenues Sales and operating revenues $ - $ - $ 339 $ 1,313 $ (174) $ 1,478 Interest, dividends and miscellaneous income - 8 (3) - (7) (2) Gain on sales of assets - - 15 42 8 65 - ----------------------------------------------------------------------------------------------------------------------------- Total revenues - 8 351 1,355 (173) 1,541 Costs and other deductions Purchases, operating and other expenses 4 - 254 817 (164) 911 Depreciation, depletion and amortization - - 61 170 - 231 Impairments - - 14 69 - 83 Dry hole costs - - 5 9 - 14 Interest expense 8 - 38 8 (9) 45 Distributions on convertible preferred securities - 8 - - - 8 - ----------------------------------------------------------------------------------------------------------------------------- Total costs and other deductions 12 8 372 1,073 (173) 1,292 Equity in earnings of subsidiaries 161 - 189 - (350) - Earnings from equity investments - - (1) 55 - 54 - ----------------------------------------------------------------------------------------------------------------------------- Earnings from continuing operations before income taxes and minority interests 149 - 167 337 (350) 303 - ----------------------------------------------------------------------------------------------------------------------------- Income taxes (3) - 6 144 - 147 Minority interests - - - 4 - 4 - ----------------------------------------------------------------------------------------------------------------------------- Earnings from continuing operations 152 - 161 189 (350) 152 Earnings from discontinued operations - - - - - - - ----------------------------------------------------------------------------------------------------------------------------- Net earnings $ 152 $ - $ 161 $ 189 $ (350) $ 152 =============================================================================================================================
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CONDENSED CONSOLIDATED EARNINGS STATEMENT Three months ended September 30, 2002 Unocal Non- Unocal Capital Union Oil Guarantor Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated - ----------------------------------------------------------------------------------------------------------------------------- Revenues Sales and operating revenues $ - $ - $ 310 $ 1,199 $ (210) $ 1,299 Interest, dividends and miscellaneous income 1 8 (68) 65 (9) (3) Gain on sales of assets - - 1 - - 1 - ----------------------------------------------------------------------------------------------------------------------------- Total revenues 1 8 243 1,264 (219) 1,297 Costs and other deductions Purchases, operating and other expenses 1 - (52) 1,089 (210) 828 Depreciation, depletion and amortization - - 81 164 - 245 Impairments - - 2 4 - 6 Dry hole costs - - 5 35 - 40 Interest expense 8 - 31 9 (8) 40 Distributions on convertible preferred securities - 8 - - - 8 - ----------------------------------------------------------------------------------------------------------------------------- Total costs and other deductions 9 8 67 1,301 (218) 1,167 Equity in earnings of subsidiaries 101 - (13) - (88) - Earnings from equity investments - - 1 34 - 35 - ----------------------------------------------------------------------------------------------------------------------------- Earnings from continuing operations before income taxes and minority interests 93 - 164 (3) (89) 165 - ----------------------------------------------------------------------------------------------------------------------------- Income taxes (3) - 63 8 - 68 Minority interests - - - 2 (4) (2) - ----------------------------------------------------------------------------------------------------------------------------- Earnings from continuing operations 96 - 101 (13) (85) 99 Earnings from discontinued operations - - - - - - Cumulative effects of accounting changes - - - - - - - ----------------------------------------------------------------------------------------------------------------------------- Net earnings $ 96 $ - $ 101 $ (13) $ (85) $ 99 =============================================================================================================================
-27-
CONDENSED CONSOLIDATED EARNINGS STATEMENT For the nine months ended September 30, 2003 Unocal Non- Unocal Capital Union Oil Guarantor Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated - ------------------------------------------------------------------------------------------------------------------------- Revenues Sales and operating revenues $ - $ - $ 1,212 $ 4,528 $ (923) $ 4,817 Interest, dividends and miscellaneous income - 25 15 6 (28) 18 Gain on sales of assets - - 49 58 8 115 - ------------------------------------------------------------------------------------------------------------------------- Total revenues - 25 1,276 4,592 (943) 4,950 Costs and other deductions Purchases, operating and other expenses 9 - 877 3,064 (914) 3,036 Depreciation, depletion and amortization - - 245 501 - 746 Impairments - - 17 69 - 86 Dry hole costs - - 63 32 - 95 Interest expense 25 1 97 25 (29) 119 Distributions on convertible preferred securities - 24 - - - 24 - ------------------------------------------------------------------------------------------------------------------------- Total costs and other deductions 34 25 1,299 3,691 (943) 4,106 Equity in earnings of subsidiaries 490 - 594 - (1,084) - Earnings from equity investments - - 6 144 - 150 - ------------------------------------------------------------------------------------------------------------------------- Earnings from continuing operations before income taxes and minority interests 456 - 577 1,045 (1,084) 994 - ------------------------------------------------------------------------------------------------------------------------- Income taxes (7) - 40 415 - 448 Minority interests - - - 8 - 8 - ------------------------------------------------------------------------------------------------------------------------- Earnings from continuing operations 463 - 537 622 (1,084) 538 Earnings from discontinued operations - - 8 - - 8 Cumulative effects of accounting changes - - (55) (28) - (83) - ------------------------------------------------------------------------------------------------------------------------- Net earnings $ 463 $ - $ 490 $ 594 $ (1,084) $ 463 =========================================================================================================================
-28-
CONDENSED CONSOLIDATED EARNINGS STATEMENT For the nine months ended September 30, 2002 Unocal Non- Unocal Capital Union Oil Guarantor Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated - ------------------------------------------------------------------------------------------------------------------------- Revenues Sales and operating revenues $ - $ - $ 805 $ 3,501 $ (611) $ 3,695 Interest, dividends and miscellaneous income 1 25 (61) 80 (28) 17 Gain (loss) on sales of assets - - 15 (13) - 2 - ------------------------------------------------------------------------------------------------------------------------- Total revenues 1 25 759 3,568 (639) 3,714 Costs and other deductions Purchases, operating and other expenses 4 - 434 2,582 (612) 2,408 Depreciation, depletion and amortization - - 261 463 - 724 Impairments - - 23 4 - 27 Dry hole costs - - 22 59 - 81 Interest expense 25 1 109 27 (28) 134 Distributions on convertible preferred securities - 24 - - - 24 - ------------------------------------------------------------------------------------------------------------------------- Total costs and other deductions 29 25 849 3,135 (640) 3,398 Equity in earnings of subsidiaries 249 - 313 - (562) - Earnings from equity investments - - 3 120 - 123 - ------------------------------------------------------------------------------------------------------------------------- Earnings from continuing operations before income taxes and minority interests 221 - 226 553 (561) 439 - ------------------------------------------------------------------------------------------------------------------------- Income taxes (10) - (23) 236 - 203 Minority interests - - - 5 (3) 2 - ------------------------------------------------------------------------------------------------------------------------- Earnings from continuing operations 231 - 249 312 (558) 234 Earnings from discontinued operations - - - 1 - 1 Cumulative effects of accounting changes - - - - - - - ------------------------------------------------------------------------------------------------------------------------- Net earnings $ 231 $ - $ 249 $ 313 $ (558) $ 235 =========================================================================================================================
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CONDENSED CONSOLIDATED BALANCE SHEET At September 30, 2003 Unocal Non- Unocal Capital Union Oil Guarantor Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated - ----------------------------------------------------------------------------------------------------------------------------- Assets Current assets Cash and cash equivalents $ - $ - $ 99 $ 386 $ - $ 485 Accounts and notes receivable - net 71 - 252 770 (84) 1,009 Inventories - - 12 120 - 132 Other current assets - - 122 31 - 153 - ----------------------------------------------------------------------------------------------------------------------------- Total current assets 71 - 485 1,307 (84) 1,779 Investments and long-term receivables - net 5,001 - 5,062 828 (9,988) 903 Properties - net - - 2,257 6,238 (3) 8,492 Other assets including goodwill 4 541 172 2,517 (2,698) 536 - ----------------------------------------------------------------------------------------------------------------------------- Total assets $5,076 $ 541 $ 7,976 $ 10,890 $ (12,773) $ 11,710 ============================================================================================================================= Liabilities and Stockholders' Equity Current liabilities Accounts payable $ - $ - $ 299 $ 816 $ (71) $ 1,044 Current portion of long-term debt and capital leases - - 215 34 - 249 Other current liabilities 51 3 284 360 (14) 684 - ----------------------------------------------------------------------------------------------------------------------------- Total current liabilities 51 3 798 1,210 (85) 1,977 Long-term debt and capital leases - - 2,078 790 - 2,868 Deferred income taxes - - (163) 872 - 709 Accrued abandonment, restoration and environmental liabilities - - 447 465 - 912 Other deferred credits and liabilities 541 - 524 2,546 (2,696) 915 Minority interests - - - 320 (292) 28 Company-obligated mandatorily redeemable convertible preferred securities of a subsidiary trust holding solely parent debentures - 522 - - - 522 Stockholders' equity 4,484 16 4,292 4,687 (9,700) 3,779 - ----------------------------------------------------------------------------------------------------------------------------- Total liabilities and stockholders' equity $5,076 $ 541 $ 7,976 $ 10,890 $ (12,773) $ 11,710 =============================================================================================================================
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CONDENSED CONSOLIDATED BALANCE SHEET At December 31, 2002 Unocal Non- Unocal Capital Union Oil Guarantor Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated - ----------------------------------------------------------------------------------------------------------------------------- Assets Current assets Cash and cash equivalents $ - $ - $ (18) $ 186 $ - $ 168 Accounts and notes receivable - net 54 - 276 738 (74) 994 Inventories - - 10 87 - 97 Other current assets 1 - 85 30 - 116 - ----------------------------------------------------------------------------------------------------------------------------- Total current assets 55 - 353 1,041 (74) 1,375 Investments and long-term receivables - net 4,562 - 4,513 960 (8,991) 1,044 Properties - net - - 2,255 5,624 - 7,879 Other assets including goodwill 3 541 272 (12) (342) 462 - ----------------------------------------------------------------------------------------------------------------------------- Total assets $4,620 $ 541 $ 7,393 $ 7,613 $ (9,407) $ 10,760 ============================================================================================================================= Liabilities and Stockholders' Equity Current liabilities Accounts payable $ - $ - $ 290 $ 788 $ (54) $ 1,024 Current portion of long-term debt and capital leases - - - 6 - 6 Other current liabilities 44 3 120 455 (20) 602 - ----------------------------------------------------------------------------------------------------------------------------- Total current liabilities 44 3 410 1,249 (74) 1,632 Long-term debt and capital leases - - 2,418 584 - 3,002 Deferred income taxes - - (116) 709 - 593 Accrued abandonment, restoration and environmental liabilities - - 320 302 - 622 Other deferred credits and liabilities 541 - 424 184 (333) 816 Minority interests - - - 313 (38) 275 Company-obligated mandatorily redeemable convertible preferred securities of a subsidiary trust holding solely parent debentures - 522 - - - 522 Stockholders' equity 4,035 16 3,937 4,272 (8,962) 3,298 - ----------------------------------------------------------------------------------------------------------------------------- Total liabilities and stockholders' equity $4,620 $ 541 $ 7,393 $ 7,613 $ (9,407) $ 10,760 =============================================================================================================================
-31-
CONDENSED CONSOLIDATED CASH FLOWS For the nine months ended September 30, 2003 Unocal Non- Unocal Capital Union Oil Guarantor Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated - ----------------------------------------------------------------------------------------------------------------------------- Cash Flows from Operating Activities $ 140 $ - $ 415 $ 1,098 $ - $1,653 Cash Flows from Investing Activities Capital expenditures and acquisitions (includes dry hole costs) - - (336) (960) - (1,296) Proceeds from sales of assets and discontinued operations - - 150 204 - 354 - ----------------------------------------------------------------------------------------------------------------------------- Net cash used in investing activities - - (186) (756) - (942) - ----------------------------------------------------------------------------------------------------------------------------- Cash Flows from Financing Activities Change in long-term debt and capital leases - - (114) 112 - (2) Dividends paid on common stock (155) - - - - (155) Minority interests - - - (257) - (257) Other 15 - 2 3 - 20 - ----------------------------------------------------------------------------------------------------------------------------- Net cash provided by (used in) financing activities (140) - (112) (142) - (394) - ----------------------------------------------------------------------------------------------------------------------------- Increase in cash and cash equivalents - - 117 200 - 317 - ----------------------------------------------------------------------------------------------------------------------------- Cash and cash equivalents at beginning of period - - (18) 186 - 168 - ----------------------------------------------------------------------------------------------------------------------------- Cash and cash equivalents at end of period $ - $ - $ 99 $ 386 $ - $ 485 =============================================================================================================================
CONDENSED CONSOLIDATED CASH FLOWS For the nine months ended September 30, 2002 Unocal Non- Unocal Capital Union Oil Guarantor Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated - ----------------------------------------------------------------------------------------------------------------------------- Cash Flows from Operating Activities $ 128 $ - $ 43 $ 1,061 $ - $1,232 Cash Flows from Investing Activities Capital expenditures and acquisitions (includes dry hole costs) - - (303) (945) - (1,248) Proceeds from sales of assets and discontinued operations - - 23 41 - 64 - ----------------------------------------------------------------------------------------------------------------------------- Net cash used in investing activities - - (280) (904) - (1,184) - ----------------------------------------------------------------------------------------------------------------------------- Cash Flows from Financing Activities Change in long-term debt and capital leases - - 284 (114) - 170 Dividends paid on common stock (147) - - - - (147) Minority interests - - - (6) - (6) Other 19 - 1 - - 20 - ----------------------------------------------------------------------------------------------------------------------------- Net cash provided by (used in) financing activities (128) - 285 (120) - 37 - ----------------------------------------------------------------------------------------------------------------------------- Increase (decrease) in cash and cash equivalents - - 48 37 - 85 - ----------------------------------------------------------------------------------------------------------------------------- Cash and cash equivalents at beginning of period - - 62 128 - 190 - ----------------------------------------------------------------------------------------------------------------------------- Cash and cash equivalents at end of period $ - $ - $ 110 $ 165 $ - $ 275 =============================================================================================================================
-32- 20. Segment Data The Company's reportable segments are: Exploration and Production, Trade, Midstream, and Geothermal and Power Operations. General corporate overhead, unallocated costs and other miscellaneous operations, including real estate, carbon and minerals and activities relating to businesses that were sold, are included under the Corporate and Other heading.
Segment Information Exploration & Production Trade For the Three Months North America International ended September 30, 2003 Millions of dollars U.S. Lower 48 Alaska Canada Far East Other - --------------------------------------------------------------------------------------------------------------------------- Sales & operating revenues $ 147 $ 63 $ 39 $ 317 $ 61 $ 633 Other income (loss) (a) 47 - 12 - 1 (1) Inter-segment revenues 248 - 36 67 - - - --------------------------------------------------------------------------------------------------------------------------- Total 442 63 87 384 62 632 Earnings from equity investments 6 - - 11 2 1 Earnings (loss) from continuing operations 77 12 15 115 21 3 Earnings from discontinued operations - - - - - - Cumulative effects of accounting changes - - - - - - - --------------------------------------------------------------------------------------------------------------------------- Net earnings (loss) 77 12 15 115 21 3 - --------------------------------------------------------------------------------------------------------------------------- Assets (at September 30, 2003) 3,325 329 1,272 3,085 963 292 - ---------------------------------------------------------------------------------------------------------------------------
Midstream Geothermal Corporate & Other Total & Power Operations Admin Net Interest Environmental & General Expense & Litigation Other (b) - --------------------------------------------------------------------------------------------------------------------------- Sales & operating revenues $ 142 $ 41 $ - $ - $ - $ 35 $ 1,478 Other income (loss) (a) 6 2 - (4) - - 63 Inter-segment revenues 2 - - - - (353) - - --------------------------------------------------------------------------------------------------------------------------- Total 150 43 - (4) - (318) 1,541 Earnings from equity investments 17 5 - - - 12 54 Earnings (loss) from continuing operations 16 19 (21) (32) (33) (40) 152 Earnings from discontinued operations - - - - - - - Cumulative effects of accounting changes - - - - - - - - --------------------------------------------------------------------------------------------------------------------------- Net earnings (loss) 16 19 (21) (32) (33) (40) 152 - --------------------------------------------------------------------------------------------------------------------------- Assets (at September 30, 2003) 654 608 - - - 1,182 11,710 - --------------------------------------------------------------------------------------------------------------------------- (a) Includes interest, dividends and miscellaneous income, and gain (loss) on sales of assets. (b) Includes eliminations and consolidation adjustments.
-33-
Segment Information Exploration & Production Trade For the Three Months North America International ended September 30, 2002 Millions of dollars U.S. Lower 48 Alaska Canada Far East Other - --------------------------------------------------------------------------------------------------------------------------- Sales & operating revenues $ 120 $ 64 $ 43 $ 283 $ 39 $ 623 Other income (loss) (a) 2 - (1) - 1 (1) Inter-segment revenues 210 - - 59 37 - - --------------------------------------------------------------------------------------------------------------------------- Total 332 64 42 342 77 622 Earnings (loss) from equity investments - - - 9 2 1 Earnings (loss) from continuing operations 13 10 (2) 129 7 (1) Earnings from discontinued operations - - - - - - - --------------------------------------------------------------------------------------------------------------------------- Net earnings (loss) 13 10 (2) 129 7 (1) - --------------------------------------------------------------------------------------------------------------------------- Assets (at December 31, 2002) 3,358 326 1,113 2,861 821 304 - ---------------------------------------------------------------------------------------------------------------------------
Midstream Geothermal Corporate & Other Total & Power Operations Admin Net Interest Environmental & General Expense & Litigation Other (b) - --------------------------------------------------------------------------------------------------------------------------- Sales & operating revenues $ 58 $ 28 $ - $ - $ - $ 41 $ 1,299 Other income (loss) (a) 1 (8) - 3 - 1 (2) Inter-segment revenues 3 - - - - (309) - - --------------------------------------------------------------------------------------------------------------------------- Total 62 20 - 3 - (267) 1,297 Earnings (loss) from equity investments 15 (3) - - - 11 35 Earnings (loss) from continuing operations 17 5 (21) (28) (14) (16) 99 Earnings from discontinued operations - - - - - - - - --------------------------------------------------------------------------------------------------------------------------- Net earnings (loss) 17 5 (21) (28) (14) (16) 99 - --------------------------------------------------------------------------------------------------------------------------- Assets (at December 31, 2002) 511 526 - - - 940 10,760 - --------------------------------------------------------------------------------------------------------------------------- (a) Includes interest, dividends and miscellaneous income, and gain (loss) on sales of assets. (b) Includes eliminations and consolidation adjustments.
-34-
Segment Information Exploration & Production Trade For the Nine Months North America International ended September 30, 2003 Millions of dollars U.S. Lower 48 Alaska Canada Far East Other - --------------------------------------------------------------------------------------------------------------------------- Sales & operating revenues $ 449 $191 $134 $ 925 $202 $2,291 Other income (loss) (a) 96 - 12 - 1 (2) Inter-segment revenues 920 - 115 230 - 1 - --------------------------------------------------------------------------------------------------------------------------- Total 1,465 191 261 1,155 203 2,290 Earnings from equity investments 15 - - 30 7 2 Earnings (loss) from continuing operations 277 41 47 352 71 (2) Earnings from discontinued operations - - - - - - Cumulative effects of accounting changes (b) 11 (43) 4 13 - - - --------------------------------------------------------------------------------------------------------------------------- Net earnings (loss) 288 (2) 51 365 71 (2) - --------------------------------------------------------------------------------------------------------------------------- Assets (at September 30, 2003) 3,325 329 1,272 3,085 963 292 - ---------------------------------------------------------------------------------------------------------------------------
Midstream Geothermal Corporate & Other Total & Power Operations Admin Net Interest Environmental & General Expense & Litigation Other (c) - --------------------------------------------------------------------------------------------------------------------------- Sales & operating revenues $ 411 $104 $ - $ - $ - $110 $ 4,817 Other income (loss) (a) 8 4 - 6 - 8 133 Inter-segment revenues 6 - - - - (1,272) - - --------------------------------------------------------------------------------------------------------------------------- Total 425 108 - 6 - (1,154) 4,950 Earnings from equity investments 49 10 - - - 37 150 Earnings (loss) from continuing operations 52 38 (66) (91) (78) (103) 538 Earnings from discontinued operations - - - - - 8 8 Cumulative effects of accounting changes (b) (2) - - - - (66) (83) - --------------------------------------------------------------------------------------------------------------------------- Net earnings (loss) 50 38 (66) (91) (78) (161) 463 - --------------------------------------------------------------------------------------------------------------------------- Assets (at September 30, 2003) 654 608 - - - 1,182 11,710 - --------------------------------------------------------------------------------------------------------------------------- (a) Includes interest, dividends and miscellaneous income, and gain (loss) on sales of assets. (b) Net of tax benefit $(48) (c) Includes eliminations and consolidation adjustments.
-35-
Segment Information Exploration & Production Trade For the Nine Months North America International ended September 30, 2002 Millions of dollars U.S. Lower 48 Alaska Canada Far East Other - --------------------------------------------------------------------------------------------------------------------------- Sales & operating revenues $ 357 $188 $143 $ 800 $ 99 $1,723 Other income (loss) (a) 6 - (1) - 1 (1) Inter-segment revenues 610 - - 173 78 1 - --------------------------------------------------------------------------------------------------------------------------- Total 973 188 142 973 178 1,723 Earnings (loss) from equity investments - - - 26 6 1 Earnings (loss) from continuing operations 37 ( 1) (5) 332 31 1 Earnings from discontinued operations - - - - - - - --------------------------------------------------------------------------------------------------------------------------- Net earnings (loss) 37 ( 1) (5) 332 31 1 - --------------------------------------------------------------------------------------------------------------------------- Assets (at December 31, 2002) 3,358 326 1,113 2,861 821 304 - ---------------------------------------------------------------------------------------------------------------------------
Midstream Geothermal Corporate & Other Total & Power Operations Admin Net Interest Environmental & General Expense & Litigation Other (b) - --------------------------------------------------------------------------------------------------------------------------- Sales & operating revenues $ 197 $ 89 $ - $ - $ - $ 99 $ 3,695 Other income (loss) (a) 3 (4) - 11 - 4 19 Inter-segment revenues 9 - - - - (871) - - --------------------------------------------------------------------------------------------------------------------------- Total 209 85 - 11 - (768) 3,714 Earnings (loss) from equity investments 52 (1) - - - 39 123 Earnings (loss) from continuing operations 59 25 (64) (93) (50) (38) 234 Earnings from discontinued operations - - - - - 1 1 - --------------------------------------------------------------------------------------------------------------------------- Net earnings (loss) 59 25 (64) (93) (50) (37) 235 - --------------------------------------------------------------------------------------------------------------------------- Assets (at December 31, 2002) 511 526 - - - 940 10,760 - --------------------------------------------------------------------------------------------------------------------------- (a) Includes interest, dividends and miscellaneous income, and gain (loss) on sales of assets. (b) Includes eliminations and consolidation adjustments.
-36- 21. Subsequent Events In October 2003, the Company announced a $300 million tender offer to repurchase debt securities due in 2005 and 2008. During October, the Company repurchased $194 million of debt principal through the tender offer at a premium of $21 million, including $115 million of the $200 million 7.20 percent notes due in 2005 and $79 million of the $100 million 6.50 percent notes due in 2008. In addition, through open market transactions, the Company repurchased an additional $96 million of various notes due from 2004 through 2009 at a premium of $12 million with an average interest rate of 6.20 percent, bringing the total repurchases to $290 million subsequent to September 30, 2003. In late October and early November 2003, the Company completed the sale of the majority of the 70 properties held for sale in the Gulf of Mexico and onshore Louisiana to Forest Oil for net proceeds totaling $218 million. This price includes adjustments that take into account the July 1, 2003 effective date of the sale (see notes 5 and 12 for discussions related to these assets). In addition, the sales of properties with preferential rights still outstanding are expected to close later in the fourth quarter of 2003. The Company has marked these assets to market at September 30, 2003, and does not anticipate material gains or losses upon the closing of the sales. In late October 2003, the Company completed a property exchange with Apache Corporation that consolidated both companies' interests in two oil and gas fields in the Gulf of Mexico region. Under the terms of the exchange, the Company received Apache's 13 percent working interest in the Unocal-operated Ship Shoal 208 field and an undisclosed amount of cash in exchange for Unocal's majority interest in the Lake Pagie field in Terrebone Parish, Louisiana. The Company now holds 100 percent of the Ship Shoal 208 field, which covers three Gulf of Mexico blocks. The Company expects to record a pre-tax gain of approximately $21 million from the transaction in the fourth quarter 2003. -37- ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. The following discussion and analysis of the consolidated financial condition and results of operations of the Company should be read in conjunction with Management's Discussion and Analysis in Item 7 of Unocal's 2002 Annual Report on Form 10-K. CONSOLIDATED RESULTS
For the Three Months For the Nine Months Ended September 30, Ended September 30, ---------------------------------------- Millions of dollars 2003 2002 2003 2002 - -------------------------------------------------------------------------------- Earnings from continuing operations $ 152 $ 99 $ 538 $ 234 Earnings from discontinued operations - - 8 1 Cumulative effects of accounting changes - - (83) - - -------------------------------------------------------------------------------- Net earnings $ 152 $ 99 $ 463 $ 235 ================================================================================
Continuing Operations Third Quarter Results: Earnings from continuing operations were $152 million in the third quarter of 2003, which was an increase of $53 million compared to the same quarter a year ago, primarily reflecting improved results from the Company's exploration and production operations due to higher worldwide natural gas and liquids prices. Higher worldwide commodity prices increased net earnings by approximately $100 million. The Company's worldwide average realized natural gas price, with no impact from hedging activities in the current quarter, was $3.60 per Mcf. This was an increase of 81 cents per Mcf, or 29 percent, from the $2.79 per Mcf realized during the same period a year ago, which included a gain of one cent per Mcf from hedging activities. In the current quarter, the Company's worldwide average realized liquids price was $27.28 per Bbl, which was an increase of $2.47 per Bbl, or 10 percent, from the same period a year ago. The Company's hedging program lowered the average realized liquids price by 6 cents per Bbl in the current quarter while the third quarter of the prior year included a loss of one cent per Bbl from hedging activities. The current quarter also included gains on asset sales of approximately $30 million after-tax related to the sale of the Company's shares in Tom Brown, Inc. ("TBI") (see note 4 to the consolidated financial statements in Item 1 of this report) and other oil and gas properties. Exploration expenses, including dry hole costs, were approximately $25 million lower in the third quarter of 2003 compared to the same period a year ago primarily as a result of lower dry hole costs in North America and lower amortization of exploratory leasehold costs worldwide. The geothermal and power operations added $14 million in earnings improvement in the current quarter as compared to the same period a year ago, primarily as a result of higher steam prices and generation in Indonesia and the impact of foreign exchange gains on the results from the Company's equity interests in gas-fired power plants in Thailand. The third quarter of 2002 included an after-tax loss of $5 million in mark-to-market accruals and realized gains/losses for non-hedge commodity derivatives recorded by the Company's Northrock Resources Ltd. ("Northrock") subsidiary. These positive variance factors were partially offset by approximately $50 million in higher after-tax impairments compared to the same period a year ago, which was primarily related to the assets held for sale. In addition, worldwide production for the current quarter was 441,000 BOE/d down from 466,000 BOE/d for the same period a year ago due primarily to lower North America production which reduced net earnings by approximately $10 million in the current quarter compared with the same period a year ago. North America liquids production averaged 80,000 Bbl/d in the current quarter, down from 92,000 Bbl/d in the same period a year ago, while natural gas production averaged 734 MMcf/d in the current quarter, down from 867 MMcf/d in the same period a year ago. Most of the production decline was due to natural declines in existing fields in the Gulf of Mexico and the divestiture of various properties in Canada, onshore U.S. and the Gulf of Mexico during the first nine months of 2003. In addition, the Company's minerals operations contributed approximately $10 million after-tax of lower earnings in the current quarter as compared to the third quarter of 2002. Higher pension related expenses also reduced net earnings by approximately $10 million in the current quarter compared to the same period a year ago. -38- The Company's after-tax environmental and litigation expenses were $38 million in the current quarter of 2003, compared with $25 million in the same period a year ago, primarily reflecting higher outside litigation support costs. The current quarter also includes an additional $6 million after-tax charge related to the Company's 2003 restructuring plan. Nine Months Results: Earnings from continuing operations were $538 million in the first nine months of 2003 compared to $234 million for the same period a year ago. Higher worldwide commodity prices increased net earnings by approximately $400 million. The Company's worldwide average realized natural gas price, including a loss of 11 cents per Mcf from hedging activities, was $3.68 per Mcf in the first nine months of 2003. This was an increase of 96 cents per Mcf, or 35 percent, from the $2.72 per Mcf, including a benefit of 4 cents per Mcf from hedging activities, realized during the first nine months of 2002. In the first nine months of 2003, the Company's worldwide average realized liquids price was $27.36 per Bbl, which was an increase of $4.98 per Bbl, or 22 percent, from the same period a year ago. The Company's hedging program lowered the average realized liquids price by 19 cents per Bbl in the first nine months of 2003 while the first nine months of 2002 included a gain of one cent per Bbl from hedging activities. International production increases also contributed approximately $35 million in higher earnings, primarily from higher Thailand liquids and natural gas production. The first nine months of 2003 included after-tax gains of approximately $60 million from asset sales, including the sale of all of the Company's stock holding in Matador Petroleum Corporation ("Matador") and the majority of its shares in TBI (see note 4 to the consolidated financial statements in Item 1 of this report). The geothermal and power operations added $13 million in earnings improvement in the nine months period of 2003 as compared to the same period a year ago, primarily as a result of the amended Salak agreements in Indonesia and the positive impact of foreign exchange rates on results from the Company's equity interests in gas-fired power plants in Thailand. The results in the first nine months of 2003 included an after-tax gain of $4 million in mark-to-market accruals and realized gains/losses for non-hedge commodity derivatives recorded by Northrock, compared with a $5 million after-tax loss in the same period a year ago. These 2003 positive variance factors were partially offset by lower North America production, the aforementioned higher asset impairments, higher pension related expenses and higher dry hole costs, which reduced net earnings by approximately $40 million, $40 million, $30 million and $10 million, respectively, in the first nine months of 2003 compared with the same period a year ago. North America liquids production averaged 84,000 Bbl/d in the first nine months of 2003, down from 96,000 Bbl/d a year ago, while natural gas production averaged 800 MMcf/d down from 910 MMcf/d for the nine months period a year ago. Most of the production decline was due to natural declines in existing fields in the Gulf of Mexico and the divestiture of various properties in Canada, onshore U.S. and the Gulf of Mexico. In addition, the Company's minerals operations contributed approximately $20 million after-tax of lower earnings in the nine months period of 2003 as compared to the same period a year ago. After-tax environmental and litigation expenses were $83 million in the first nine months of 2003, compared with $62 million in the same period a year ago, primarily due to higher litigation expenses including related outside support costs. The first nine months of 2003 included the company-wide $23 million restructuring charge, while the same period a year ago included a $12 million restructuring charge for the Gulf Region business unit. Cumulative Effects of Accounting Changes In the first quarter of 2003, the Company recorded a non-cash $83 million after-tax charge consisting of the cumulative effect of a change in accounting principle related to the initial adoption of Statement of Financial Accounting Standards ("SFAS") No. 143, "Accounting for Asset Retirement Obligations." The Company also increased its accrued abandonment and restoration liabilities by $268 million and increased its net properties by $138 million on the consolidated balance sheet as a result of the adoption of SFAS No.143. Revenues Revenues from continuing operations for the third quarter of 2003 were $1.54 billion compared with $1.3 billion for the same period a year ago. In the first nine months of 2003, total revenues from continuing operations were $4.95 billion compared with $3.71 billion for the same period a year ago. The increases, in both the quarter and nine months amounts, primarily reflected higher crude oil and natural gas prices. -39-
OPERATING HIGHLIGHTS UNOCAL CORPORATION For the Three Months For the Nine Months Ended September 30, Ended September 30, ----------------------------------------- 2003 2002 2003 2002 - -------------------------------------------------------------------------------- North America Net Daily Production Liquids (thousand barrels) U.S. Lower 48 (a) (b) 42 52 45 54 Alaska 21 24 22 25 Canada 17 16 17 17 - -------------------------------------------------------------------------------- Total liquids 80 92 84 96 Natural gas - dry basis (million cubic feet) U.S. Lower 48 (a) (b) 595 716 650 740 Alaska 49 61 59 79 Canada 90 90 91 91 - -------------------------------------------------------------------------------- Total natural gas 734 867 800 910 North America Average Prices (excluding hedging activities) (c) Liquids (per barrel) U. S. Lower 48 $ 27.92 $ 24.85 $ 28.04 $ 22.24 Alaska $ 29.39 $ 26.10 $ 29.87 $ 23.36 Canada $ 24.02 $ 22.70 $ 25.37 $ 20.29 Average $ 27.47 $ 24.79 $ 27.96 $ 22.18 Natural gas (per mcf) U. S. Lower 48 $ 4.78 $ 2.95 $ 5.39 $ 2.78 Alaska $ 1.46 $ 1.20 $ 1.27 $ 1.48 Canada $ 4.96 $ 2.08 $ 5.24 $ 2.38 Average $ 4.57 $ 2.73 $ 5.05 $ 2.62 - -------------------------------------------------------------------------------- North America Average Prices (including hedging activities) (c) Liquids (per barrel) U. S. Lower 48 $ 27.71 $ 24.84 $ 27.37 $ 22.28 Alaska $ 29.39 $ 26.10 $ 29.87 $ 23.36 Canada $ 24.02 $ 22.70 $ 25.37 $ 20.29 Average $ 27.36 $ 24.78 $ 27.59 $ 22.20 Natural gas (per mcf) U. S. Lower 48 $ 4.82 $ 2.97 $ 5.11 $ 2.87 Alaska $ 1.46 $ 1.20 $ 1.27 $ 1.48 Canada $ 4.64 $ 2.10 $ 4.93 $ 2.44 Average $ 4.57 $ 2.75 $ 4.79 $ 2.69 - -------------------------------------------------------------------------------- (a)Includes proportional interests in production of equity investees. (b)Includes minority interests of : Liquids - 8 1 8 Natural gas - 94 7 96 Barrels oil equivalent - 24 2 24 (c)Excludes gains/losses on derivative positions not accounted for as hedges and ineffective portions of hedges.
-40-
OPERATING HIGHLIGHTS (CONTINUED) UNOCAL CORPORATION For the Three Months For the Nine Months Ended September 30, Ended September 30, ----------------------------------------- 2003 2002 2003 2002 - -------------------------------------------------------------------------------- International Net Daily Production (d) Liquids (thousand barrels) Far East 59 52 58 53 Other (a) 20 20 20 20 - -------------------------------------------------------------------------------- Total liquids 79 72 78 73 Natural gas - dry basis (million cubic feet) Far East 883 859 888 855 Other (a) 74 83 91 79 - -------------------------------------------------------------------------------- Total natural gas 957 942 979 934 International Average Prices (d) (e) Liquids (per barrel) Far East $26.65 $23.99 $26.92 $21.95 Other $29.19 $26.94 $27.74 $24.62 Average $27.20 $24.84 $27.11 $22.62 Natural gas (per mcf) Far East $2.86 $2.84 $2.79 $2.74 Other $2.93 $2.80 $2.88 $2.70 Average $2.87 $2.83 $2.80 $2.74 - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- Worldwide Net Daily Production (a) (b) (d) Liquids (thousand barrels) 159 164 162 169 Natural gas - dry basis (million cubic feet) 1,691 1,809 1,779 1,844 Barrels oil equivalent (thousands) 441 466 458 476 Worldwide Average Prices (excluding hedging activities) (c) Liquids (per barrel) $27.34 $24.82 $27.55 $22.37 Natural gas (per mcf) $3.60 $2.78 $3.79 $2.68 Worldwide Average Prices (including hedging activities) (c) (e) Liquids (per barrel) $27.28 $24.81 $27.36 $22.38 Natural gas (per mcf) $3.60 $2.79 $3.68 $2.72 - -------------------------------------------------------------------------------- (a)Includes proportional interests in production of equity investees. (b)Includes minority interests of : Liquids - 8 1 8 Natural gas - 94 7 96 Barrels oil equivalent - 24 2 24 (c)Excludes gains/losses on derivative positions not accounted for as hedges and ineffective portions of hedges. (d)International production is presented utilizing the economic interest method. (e)International did not have any hedging activities.
Selected Costs and Other Deductions Administrative and general expense in 2003 included a $27 million pre-tax charge as a result of the restructuring program announced in June and an additional $10 million pre-tax restructuring charge in September. The increase in administrative and general expense also reflected higher pension-related expenses in 2003. -41- Exploration and Production The Company engages in oil and gas exploration, development and production worldwide. The results of this segment are discussed under the geographical breakdown of North America and International: North America - Included in this category are the U.S. Lower 48, Alaska and Canada oil and gas operations. The emphasis of the U.S. Lower 48 operations is on the onshore, the shelf and deepwater areas of the Gulf of Mexico region and the Permian and San Juan Basins in west Texas and New Mexico. A substantial portion of the crude oil and natural gas produced in the U.S. Lower 48 operations is sold to the Company's Trade business segment. Natural gas produced by Northrock in Canada is also sold to the Company's Trade business segment. The remainder of U.S. Lower 48 and Canada production is sold to third parties. In Alaska, the majority of natural gas production, pursuant to agreements with the purchaser of the Company's former agricultural products business, is sold to a fertilizer plant in Nikiski, Alaska. In addition, the Company uses hydrocarbon derivative financial instruments such as futures, swaps and options to hedge portions of the Company's exposure to commodity price fluctuations. Third Quarter Results: Earnings from continuing operations were $104 million in the third quarter of 2003 compared to $21 million for the same period a year ago, which was an increase of $83 million. The increase was primarily due to higher natural gas and liquids prices, which increased net earnings by approximately $90 million. In addition, the current quarter included approximately $30 million after-tax in gains on asset sales primarily from the sale of TBI stock. The current quarter results also reflected approximately $20 million after-tax in lower exploration expenses, including dry hole costs. The third quarter of 2002 included an after-tax loss of $5 million in mark-to-market accruals and realized gains/losses for non-hedge commodity derivatives recorded by Northrock. These positive factors were partially offset by lower natural gas and liquids production, which reduced after-tax earnings by approximately $10 million. The current quarter also included after-tax impairment charges of $47 million primarily related to the Gulf of Mexico assets held for sale. Nine Months Results: Earnings from continuing operations were $365 million in the first nine months of 2003 compared to $31 million for the same period a year ago. The increase was primarily due to higher natural gas and liquids prices, which increased net earnings by approximately $355 million. In addition, the Company recorded approximately $55 million after-tax in asset sale gains, primarily from the sale of TBI and Matador common stock. The first nine months of 2003 included an after-tax gain of $4 million in mark-to-market accruals and realized gains/losses for non-hedge commodity derivatives recorded by Northrock, while the comparable period a year ago included an after-tax loss of $5 million. These positive factors were partially offset by the aforementioned impairments primarily related to the Gulf of Mexico assets held for sale, lower natural gas and liquids production, higher exploration expenses including dry hole costs, which reduced after-tax earnings by approximately $47 million, $40 million and $25 million, respectively. The nine months period of 2002 included a $12 million after-tax impairment in the Alaska business unit and a $12 million after-tax restructuring charge in the Gulf Region business unit. International - Unocal's International operations include oil and gas exploration and production activities outside of North America. The Company operates or participates in production operations in Thailand, Indonesia, Myanmar, Bangladesh, the Netherlands, Azerbaijan, the Democratic Republic of Congo and Brazil. International operations also include the Company's exploration activities and the development of energy projects primarily in Asia, Australia, Latin America and West Africa. Third Quarter Results: Earnings from continuing operations totaled $136 million in the current quarter, unchanged from the same period a year ago. Higher liquids and natural gas prices improved net earnings by $11 million. The results for the current quarter also benefited from $7 million in lower exploration expenses, including dry hole costs. These positive factors were offset by approximately $15 million in increased income tax expense due to higher effective tax rates, primarily caused by a weakening in the U.S. dollar against the Thai baht. -42- Nine Months Results: Earnings from continuing operations totaled $423 million in the first nine months of 2003 compared to $363 million in the same period a year ago, which was an increase of $60 million. The increase was primarily due to approximately $55 million in higher liquids and natural gas prices and $35 million in higher liquids and natural gas production. These positive factors were partially offset by approximately $25 million in higher DD&A expense (including asset retirement obligation accretion) and $5 million in increased income taxes due to higher effective tax rates, primarily due to the weakening of the U.S. dollar against the Thai baht. The higher natural gas production was primarily from increased demand tied to higher electric power needs in Thailand and higher production in Bangladesh. Higher liquids production was due to the Yala-Plamuk and Pailin Phase 2 projects in Thailand. TRADE The Trade segment externally markets the majority of the Company's worldwide liquids production and North American natural gas production, excluding production of the Alaska business unit. It is also responsible for executing various derivative contracts on behalf of the Exploration and Production segment in order to manage the Company's exposures to commodity price changes. The Trade segment also purchases liquids and natural gas from certain of the Company's royalty owners, joint venture partners and unaffiliated oil and gas producing and trading companies for resale. In addition, the segment trades hydrocarbon derivative instruments, for which hedge accounting is not used, to exploit anticipated opportunities arising from commodity price fluctuations. The segment also purchases limited amounts of physical inventories for energy trading purposes when arbitrage opportunities arise. These commodity risk-management and trading activities are subject to internal restrictions, including value at risk limits, which measure the Company's potential loss from likely changes in market prices. Third Quarter Results: Earnings from continuing operations totaled $3 million in the current quarter compared to a loss of $1 million in the same period a year ago. The higher results reflect gains from natural gas and crude oil trading activities, which were positively impacted by volatile commodity prices. Sales and operating revenues from the Trade business segment were $633 million in the current quarter compared to $623 million in the same quarter a year ago, which was an increase of $10 million. These revenues represented approximately 43 percent and 48 percent of the Company's total sales and operating revenues for the third quarters of 2003 and 2002, respectively. Increases in natural gas and crude oil revenues, as a result of higher prices, were partially offset by lower natural gas and crude oil volumes. Nine Months Results: The results for the first nine months were a loss of $2 million compared to earnings of $1 million in the same period a year ago. The decrease was primarily due to lower results related to domestic crude oil and natural gas marketing activities, which were negatively impacted by volatile commodity prices. Sales and operating revenues were $2.29 billion in the first nine months of 2003 compared to $1.72 billion in the same period a year ago, which was an increase of` $568 million. These revenues represented approximately 48 percent and 47 percent of the Company's total sales and operating revenues for the first nine months of 2003 and 2002, respectively. In the first nine months of 2003, natural gas revenues increased by approximately $414 million and crude oil revenues increased by approximately $157 million, primarily due to higher commodity prices, as compared to the same period a year ago. Higher commodity prices were partially offset by lower crude oil and natural gas volumes. -43- MIDSTREAM The Midstream segment is comprised of the Company's equity interests in certain petroleum pipeline companies, wholly-owned pipeline systems throughout the U.S., and the Company's North America gas storage business. Third Quarter Results: Earnings from continuing operations totaled $16 million in the current quarter compared to $17 million in the same period a year ago. The decrease was due primarily to $4 million after-tax in impairments related to the Trans-Andean oil pipeline, which transports crude oil from Argentina to Chile and a U.S. pipeline associated with exploration and production assets held for sale in the Gulf of Mexico region. The results for the prior year quarter included a $2 million after-tax impairment of assets of a U.S. pipeline company in which the Company owns an equity interest. Nine Months Results: Earnings from continuing operations totaled $52 million in the first nine months of 2003 compared to $59 million in the same period a year ago. The decrease was due primarily to $5 million in lower results from the pipelines and gas storage businesses and $3 million from expenses related to the Baku-Tbilisi-Ceyhan ("BTC") pipeline project. The nine months results of 2003 and 2002 also reflect the aforementioned asset impairments. GEOTHERMAL AND POWER OPERATIONS The Geothermal and Power Operations business segment produces geothermal steam for power generation, with operations in the Philippines and Indonesia. The segment's activities also include the operation of geothermal steam-fired power plants in Indonesia and equity interests in gas-fired power plants in Thailand. The Company's non-exploration and production business development activities, primarily power-related, are also included in this segment. Third Quarter Results: Earnings from continuing operations totaled $19 million in the current quarter compared to $5 million in the same period a year ago. The current period results were positively impacted by higher steam prices and generation in Indonesia. In addition, the current period benefited from improved results from the Company's equity interests in gas-fired power plants in Thailand. Nine Months Results: Earnings from continuing operations totaled $38 million in the first nine months of 2003 compared to $25 million in the same period a year ago. The current period results reflect improvements from the amended Salak agreements in Indonesia. In addition, the nine months results in 2003 reflect higher results from the Company's equity interests in gas-fired plants in Thailand and lower non-exploration and production business development expenses as compared to the same period a year ago. CORPORATE AND OTHER Corporate and Other includes general corporate overhead, miscellaneous operations (including real estate activities, carbon and minerals) and other corporate unallocated costs (including environmental and litigation expense). Net interest expense represents interest expense, net of interest income and capitalized interest. Third Quarter Results: The results for the current quarter were a loss of $126 million compared to a loss of $79 million in the same period a year ago. After-tax expenses for environmental and litigation matters for the current quarter were $38 million compared to $25 million after-tax for the same period a year ago, primarily reflecting higher outside litigation support costs. In addition, the current quarter reflected approximately $10 million after-tax in lower results from the Company's minerals business, $10 million after-tax in higher pension related expenses, a $6 million in restructuring charge and $4 million in higher net after-tax interest expense primarily due to lower interest income and lower capitalized interest. -44- Nine Months Results: The results for the first nine months were a loss of $338 million compared to a loss of $245 million in the same period a year ago. The first nine months of 2003 included $23 million after-tax restructuring charge and higher pension related expenses of approximately $30 million. After-tax expenses for environmental and litigation matters for the nine months of 2003 were $83 million compared to $63 million after-tax for the same period a year ago. In addition, the nine months results of 2003 reflect approximately $20 million after-tax in lower earnings from the minerals business. Restructuring In June 2003, the Company accrued a $27 million pre-tax restructuring charge and adopted a plan for streamlining the organizational structures in order to align them with the Company's portfolio requirements and business needs. In the third quarter of 2003, the Company accrued an additional $10 million pre-tax restructuring charge to reflect continued streamlining of the organizational structures. The charge is included in selling, administrative and general expense on the consolidated earnings statement. The following table reflects the 2003 restructuring activity by quarter: - ----------------------- ----------------- ----------- ------------ ------------- Millions of dollars # Employees added Training / Post- (except employees) to restructuring Termination Outplacement retirement plan Costs Costs Benefit Costs - ----------------------- ----------------- ----------- ------------ ------------- 1st Quarter Accrual - - - - - ----------------------- ----------------- ----------- ------------ ------------- 1st Quarter Payments - - - - ----------------------- ----------------- ----------- ------------ ------------- Liability at 3/31/2003 - - - - ----------------------- ----------------- ----------- ------------ ------------- 2nd Quarter Accrual 219 21 2 4 - ----------------------- ----------------- ----------- ------------ ------------- 2nd Quarter Payments - - - - ----------------------- ----------------- ----------- ------------ ------------- Liability at 6/30/2003 21 2 4 - ----------------------- ----------------- ----------- ------------ ------------- 3rd Quarter Accrual 127 9 - 1 - ----------------------- ----------------- ----------- ------------ ------------- 3rd Quarter Payments 2 - - - ----------------------- ----------------- ----------- ------------ ------------- Liability at 9/30/2003 28 2 5 - ----------------------- ----------------- ----------- ------------ ------------- The majority of the liabilities are expected to be paid in 2003 and 2004. At September 30, 2003, 321 of 346 employees had been terminated or had been advised of planned termination dates as a result of the plan. In June 2002, the Company's Gulf Region business unit, which is part of the U.S. Lower 48 operations in the Exploration and Production segment, adopted a restructuring plan that resulted in the accrual of a $19 million pre-tax restructuring charge. The charge included the estimated costs of terminating 202 employees, all of whom were terminated in 2002. At September 30, 2003, approximately $18 million of the restructuring costs had been paid and charged against the liability, leaving accrued costs of $1 million on the consolidated balance sheet. The remaining costs are expected to be paid by the end of 2003. In November 2002, the Company adopted a restructuring plan that resulted in the accrual of a $4 million pre-tax restructuring charge related to Exploration and Production operations in Alaska. The restructuring charge reflected the costs of terminating 46 employees, of whom 43 had been terminated as of September 30, 2003. At September 30, 2003, approximately $3 million of the restructuring costs had been paid. The plan will essentially be completed at the end of 2003. -45- FINANCIAL CONDITION Cash flows from operating activities, including working capital and other changes, were $1.65 billion for the nine months ended September 30, 2003, compared with $1.23 billion for the same period a year ago. The increase principally reflected the effects of higher worldwide commodity prices. The positive impact from higher prices was partially offset by higher income tax payments, compared to the same period a year ago, and the repayment of the outstanding balance under the Company's accounts receivable securitization program. Pre-tax proceeds from asset sales (including those classified as discontinued operations) were $354 million for the nine months ended September 30, 2003. The Company received $122 million from the sale of most of its shares in Tom Brown Inc. and $80 million from the sale of its common stock in Matador. The Company also completed the sale of various properties in Canada, onshore U.S. and the Gulf of Mexico, which netted the Company approximately $118 million in proceeds. Other miscellaneous property sales netted the Company $23 million in proceeds and $11 million related to a participation payment was received from the purchaser of the Company's former West Coast refining, marketing and transportation assets covering price differences between California Air Resources Board Phase 2 gasoline and conventional gasoline. Pre-tax proceeds from asset sales (including those classified as discontinued operations) were $64 million for the nine months ended September 30, 2002. These proceeds included $29 million from the sale of oil and gas producing properties in the U.S. by the Company's Pure subsidiary. Sale proceeds also included $17 million from various other oil and gas asset sales, $15 million in other miscellaneous properties and $3 million related to the aforementioned participation payment. Capital expenditures were $1.3 billion for the first nine months of 2003 compared with $1.25 billion in the same period a year ago. Capital expenditures for 2003 are currently forecast at approximately $1.75 billion. Capital expenditures reflect higher spending on development projects, including the Caspian crude oil development and the Baku-Tbilisi-Ceyhan ("BTC") pipeline project, the West Seno field in deepwater Indonesia and Mad Dog field in the Gulf of Mexico. In the first nine months of 2003, the Company's capital expenditures included approximately $580 million for the development of undeveloped proved oil and gas reserves, primarily in Indonesia, Azerbaijan, Thailand and the deepwater Gulf of Mexico. The Company's total consolidated debt, including current maturities, at September 30, 2003, was $3.12 billion, approximately $100 million more than at the end of 2002. During the first nine months of 2003, the Company retired $89 million in 9.25% debentures and paid down $10 million of medium-term notes which matured. The Company also repurchased $15 million of the $200 million outstanding balance in 6.375% notes due in 2004, $10 million of the $350 million outstanding balance in 7.35% notes due in 2009 and repaid $20 million of 6.20% Industrial Development Revenue Bonds. In addition, the Company prepaid a $5 million capital lease on a natural gasoline plant and paid down an additional $7 million of miscellaneous debt. These decreases in debt and capital leases were offset by $154 million drawn under the Overseas Private Investment Corporation ("OPIC") Financing Agreement for the first phase of the West Seno development project in Indonesia. In addition, effective in the third quarter of 2003, FASB Interpretation No. 46 required the Company to consolidate DSPL, resulting in the reporting of $78 million as long-term debt on the consolidated balance sheet at September 30, 2003. In July the Company paid off the $252 million limited partner interest in Spirit Energy 76 Development, L.P. of which $242 million would have been reclassified as long-term debt in the third quarter pursuant to FASB Interpretation No. 46 (see note 13 for further detail on the Company's long-term debt). Cash and cash equivalents on hand totaled $485 million at September 30, 2003, up from $168 million at the end of 2002. -46- The Company has two primary credit facilities in place: a $400 million 364-day credit agreement and a $600 million 5-year credit agreement, maturing October 2006. No borrowings were outstanding under either facility at September 30, 2003. The agreements provide for the termination of the loan commitments and require the prepayment of all outstanding borrowings in the event that (1) any person or group becomes the beneficial owner of more than 30 percent of the then outstanding voting stock of Unocal other than in a transaction having the approval of Unocal's board of directors, at least a majority of which are continuing directors, or (2) if continuing directors shall cease to constitute at least a majority of the board. The agreements do not have drawdown restrictions or prepayment obligations in the event of a credit rating downgrade. Both agreements limit the Company's total debt to total capitalization ratio to 70 percent (total capitalization is defined as total debt plus total equity, with the Company's convertible preferred securities included as equity in the ratio calculation.) In addition, the Company also has a 3-year $295 million Canadian dollar-denominated non-revolving credit facility with a variable rate of interest. At September 30, 2003, the borrowing under the Canadian credit facility translated to $216 million, using applicable foreign exchange rates. Based on current commodity prices and current development projects, the Company expects cash generated from operating activities, asset sales and cash on hand in 2003 to be sufficient to cover its operating and capital spending requirements and to meet dividend payments and to pay down debt. The Company has substantial borrowing capacity to enable it to meet unanticipated cash requirements. The Company relies on the commercial paper market, its accounts receivable securitization program and its revolving credit facilities to cover near-term borrowing requirements. At September 30, 2003, the Company did not have an outstanding balance under its accounts receivable securitization program, which was at $108 million at year-end 2002. The Company also had in place a universal shelf registration statement as of September 30, 2003, with an unutilized balance of approximately $1.539 billion, which is available for the future issuance of other debt and/or equity securities depending on the Company's needs and market conditions. From time to time, the Company may also look to fund some of its long-term projects using other financing sources, including multilateral and bilateral agencies. Maintaining investment-grade credit ratings, that is "BBB- / Baa3" and above from Standard & Poor's Ratings Services and Moody's Investors Service, Inc., respectively, is a significant factor in the Company's ability to raise short-term and long-term financing. As a result of the Company's current investment grade ratings, the Company has access to both the commercial paper and bank loan markets. The Company currently has a BBB+ / Baa2 credit rating by Standard & Poor's and Moody's, respectively, and an A-2 / Prime-2 for its commercial paper ratings. Moody's and Standard & Poor's outlooks remained stable for the Company's long term debt and commercial paper ratings. The Company does not believe it has a significant exposure to liquidity risk in the event of a credit rating downgrade. -47- ENVIRONMENTAL MATTERS The Company is committed to operating its business in a manner that is environmentally responsible. This commitment is fundamental to the Company's core values. As part of this commitment, the Company has procedures in place to audit and monitor its environmental performance. In addition, it has implemented programs to identify and address environmental risks throughout the Company. Costs associated with identified environmental remediation obligations have been accrued in a reserve for such obligations. At September 30, 2003, the Company's remediation reserve totaled $265 million, of which $144 million was included in current liabilities. During the nine months period ended September 30, 2003, cash payments of $53 million were applied against the reserve and $77 million was added to the reserve. The Company may also incur additional liabilities in the future at sites where remediation liabilities are probable but future environmental costs are not presently reasonably estimable because the sites have not been assessed or the assessments have not advanced to stages where costs are reasonably estimable. At those sites where investigations or feasibility studies have advanced to the stage of analyzing feasible alternative remedies and/or ranges of costs, the Company estimates that it could incur possible additional remediation costs aggregating approximately $210 million. The Company's total environmental reserve and possible additional liability amounts are grouped into the following four categories.
At September 30, 2003 ---------------------------- Possible Additional Millions of dollars Reserve Costs - -------------------------------------------------------------------------------- Superfund and similar sites $ 16 $ 15 Active Company facilities 32 30 Company facilities sold with retained liabilities and former Company-operated sites 99 80 Inactive or closed Company facilities 118 85 - -------------------------------------------------------------------------------- Total $ 265 $ 210 ================================================================================
Also see notes 16 and 17 to the consolidated financial statements in Item 1 of this report for additional information on environmental related matters. During the first nine months of 2003, the Company accrued $42 million related to sites in the "Inactive or closed Company facilities" category primarily for the Guadalupe oil field located on the central California coast and for remediation projects at the Company's former refinery in Beaumont, Texas. For the Guadalupe oil field site, it was determined that contaminated soil excavated from the site will probably be taken to an offsite landfill for disposal. The soil is contaminated with diluent, a kerosene-like additive used in the field's former operations. Previously, the Company had planned to remediate the soil on-site; however, a preliminary draft report for the ecological risk study being conducted indicates that on-site remediation is not feasible. The provisions recorded for the site include the costs for the offsite disposal alternative. The provisions recorded for the Guadalupe oil field also include estimated costs for remediation work that is ongoing at the site. This work includes groundwater monitoring, operation and maintenance of remedial systems, restoration, agency oversight, permitting, and site assessment. The provisions for these costs are based on data from various studies and assessments that have been completed for the site in conjunction with data provided by the project management system the Company has in place. A provision was also recorded for the Company's former Beaumont, Texas refinery. The Company has been working with the Texas Commission on Environmental Quality ("TCEQ") to develop plans for closing impoundments used in the site's former operations and for other remediation projects. In the first nine months of 2003, the Company recorded a provision for the revised estimated costs of the impoundment closure plan based on the TCEQ initial draft permit that was issued for the site. -48- During the first nine months of 2003, provisions of $27 million were recorded for the "Company facilities sold with retained liabilities and former Company-operated sites" category. These provisions included the estimated cleanup costs for oil fields located in Michigan and California that were formerly operated by the Company. The estimated costs are based on assessments recently performed at the sites, higher than anticipated volumes of contaminated soil at existing sites and higher remediation costs for soil excavation and disposal than originally anticipated. The provisions for this category of sites were also the result of revised remediation cost estimates that were identified during the first and second quarters of 2003 for former service station sites. The Company recorded provisions of $8 million during the first nine months of 2003 for the "Active Company facilities" category of sites. The provisions were primarily for the remedial investigation and feasibility study (RI/FS) being performed at a molybdenum mine located in Questa, New Mexico, that is owned by the Company's Molycorp, Inc. ("Molycorp") subsidiary. Molycorp has been working closely with the U.S. Environmental Protection Agency and the State of New Mexico in conducting the RI/FS at the mine during the year. The RI/FS is being performed to determine if past mining operations have had an adverse impact on the environment. Numerous additions and changes to the RI/FS scope have been required by the agencies, which will require a higher level of effort than originally projected. During the first nine months of 2003, estimated possible additional costs in excess of amounts included in the reserves for remediation obligations decreased by $35 million. The decrease was primarily for sites in the "Active Company facilities" category, as a result of the reclassification of costs to asset retirement obligations under SFAS No. 143 for the Company's Molycorp subsidiary (see note 2 for further detail). The decrease was also the result of the Company lowering its estimated costs for the "Inactive or closed Company facilities" category of sites by $20 million. These costs were included in the amounts added to the reserve for the Guadalupe oil field and the Beaumont Refinery sites as discussed above. Partially offsetting the foregoing decreases was an increase of $5 million in possible additional costs for the "Superfund and similar sites" category. The increase is based on preliminary information that the Company has received regarding possible payments for remediation-related work that may need to be made for two sites located in California. Estimated possible additional costs for the "Company facilities sold with retained liabilities and former Company-operated sites" category also increased by $5 million during the first nine months of 2003. This increase was primarily for costs that may be incurred related to the cleanup of various sites that were part of the auto/truckstop system that the Company sold in 1993. -49- OUTLOOK Certain of the statements in this discussion, as well as other forward-looking statements within this document, contain estimates and projections of amounts of or increases/decreases in future revenues, earnings, cash flows, capital expenditures, assets, liabilities and other financial items and of future levels of or increases/decreases in reserves, production, sales including related costs and prices, drilling activities and other statistical items; plans and objectives of management regarding the Company's future operations, products and services; and certain assumptions underlying such estimates, projection plans and objectives. While these forward-looking statements are made in good faith, future operating, market, competitive, legal, economic, political, environmental, and other conditions and events could cause actual results to differ materially from those in the forward-looking statements. See pages 56 through 64 of Management's Discussion and Analysis in Item 7 of the Company's 2002 Annual Report on Form 10-K for a discussion of certain of such conditions and events. The economic situation in Asia, where most of the Company's international activity is centered, is still recovering with positive signs showing in the region. The Company looks at the natural gas market in Asia as one of its major strategic investments and believes that the governments in the region are committed to undertaking the reforms and restructuring necessary to enable their nations to continue their recoveries from the downturn. Volatile energy prices are expected to continue to impact financial results. The Company expects energy prices to remain volatile due to changes in climate conditions, worldwide demand, crude oil and natural gas inventory levels, production quotas set by OPEC, current and future worldwide political instability, especially concerning Iraq and Nigeria, security and other factors. The Company currently estimates its full-year 2003 production to average between 450,000 to 455,000 BOE per day. This production forecast includes the impact of the sale of nearly 7,000 BOE per day of equity production from the Company's holdings in TBI and Matador, the sale of more than 20,000 BOE per day of production to Forest Oil Corporation and others during the fourth quarter, the associated production loss of approximately 5,000 BOE per day from other divestitures that the Company has completed so far this year, and the start-up delay of the West Seno field in Indonesia. The Company's total actual production for the year could also be impacted by cost recovery volume fluctuations under the Company's various foreign PSCs due to changes in commodity prices, demand for natural gas in Thailand, the rate of ramp-up of production from the West Seno field in Indonesia and production and exploration performance in the Gulf of Mexico. For the fourth quarter of 2003, the Company has hedged 25 million MMBtu (million British thermal units) of Lower 48 natural gas production and 4 million Bbl of Lower 48 crude oil production, together representing approximately 70 percent of expected Lower 48 BOE production volume. Fourth quarter hedges include fixed price sales for 16 million MMBtu of natural gas at $5.99 per MMBtu and 3.1 million Bbl of crude oil at $31.14 per Bbl. In addition, the Company has hedged 9 million MMBtu of natural gas with pricing collars between $4.62 and $3.77 per MMBtu and 600,000 Bbl of crude oil with collars between $32.24 and $27.41 per Bbl. Based on current prices, the Company's net earnings for the fourth quarter are expected to change $8 million for each $1 change in the Company's average worldwide realized price for crude oil and $3.5 million for every 10-cent change in its average realized North America natural gas price, excluding the effect of hedging activities. The Company has an active exploratory drilling program and forecasts fourth quarter pre-tax dry hole costs of $50 million to $65 million. -50- Exploration and Production - North America U.S. Lower 48 The Company continues its deep shelf program in the Gulf of Mexico. Production at the Red Pepper shelf discovery on High Island Block 37 commenced in October, adding to the Company's Harvest deep shelf discovery on West Cameron Block 44 that commenced in late June and two other deep shelf producing fields. In late October, the Company drilled a successful appraisal well on its Harvest deep shelf field. The well was drilled to a total depth of 14,322 feet and encountered more than 140 feet of net natural gas pay. The Company expects to place the Harvest-2 well on production in mid-December and is in the process of formulating plans for a second appraisal well. The Company holds a 44-percent working interest in the field. The Company expects to continue its deep shelf drilling activity for the remainder of 2003, which is expected to bring the total number of deep shelf exploratory wells drilled to 11 for the year. In the Gulf of Mexico deepwater, the Company completed a discovery well on the St. Malo prospect located on Walker Ridge Block 678. The discovery well encountered more than 450 feet of net oil pay. Based on the evaluation of this well, the Company expects to begin an appraisal program in 2004. The Company holds a 28.75 percent working interest in the prospect. In addition, the Company farmed-in to an exploratory well which is currently being drilled on the Puma prospect to earn a 15 percent working interest. The prospect is an exploration play offsetting the Mad Dog discovery. The Company expects to drill an additional well before the end of 2003. The Company continues the funding of the development of the Mad Dog field in which the Company has a 15.6 percent non-operating working interest. The Company anticipates first production in the first half of 2005, with gross expected peak production of 75 MBbl/d of liquids and 30 MMcf/d of natural gas in 2007. The Company also expects the co-venture integrated project team of the K-2 discovery to complete a development plan by the end of 2003 with project sanctioning to occur in early 2004. The Company and its co-venturers are working on development options with the aim of sanctioning development of the Champlain discovery in 2004. The Company completed a successful appraisal well on the Champlain discovery in July 2003 and has a 30-percent working interest in the prospect. The Company continues to move forward with studies on development options for its Trident discovery in the deepwater Gulf of Mexico. The Company is in discussions with all the operators in the area about development scenarios and joint development planning. The Company is the operator of the discovery and has a 59.5 percent working interest in a seven-block area. In the fourth quarter of 2003, the Company expects to complete the sale of the 70 properties held for sale in the Gulf of Mexico and onshore Louisiana to Forest Oil Corporation and others for net proceeds totaling approximately $233 million. The effective date of the sale was July 1, 2003 (see notes 5 and 12 for discussions related to these assets). Of the total expected proceeds, $218 million had been received from Forest Oil as of November 12, 2003, with an additional $15 million expected to be received by year-end from Forest and other working interest owners in the properties who exercised their preferential rights. The Company continues to move forward with the divestiture of an additional 30 properties held for sale in the Gulf of Mexico region. The sale of these remaining properties is expected to close later in the fourth quarter of 2003. In late October 2003, the Company completed a property exchange with Apache Corporation that consolidated both companies' interests in two oil and gas fields in the Gulf of Mexico region. Under the terms of the exchange, the Company received Apache's 13 percent working interest in the Unocal-operated Ship Shoal 208 field and an undisclosed amount of cash in exchange for Unocal's majority interest in the Lake Pagie field in Terrebone Parish, Louisiana. The Company now holds 100 percent of the Ship Shoal 208 field, which covers three Gulf of Mexico blocks. The Company expects to record a pre-tax gain of approximately $21 million from the transaction in the fourth quarter 2003. This consolidation of interests is part of the restructuring program began by the Company earlier this year to improve the profitability and sustainability of its Lower-48 exploration and production businesses. The Company anticipates completion of the divestiture program by the end of 2003 (see note 12 to the consolidated financial statements in Item 1 of this report). -51- Alaska The Ninilchik Unit, on the South Kenai peninsula, began first production from two wells in September 2003 and the Company expects the remaining three wells to be brought on-line over the remainder of the year. The two wells are currently producing 16 MMcf/d gross. The Company has a 40 percent non-operating interest in the unit. Sales of Ninilchik natural gas to Enstar are scheduled to commence in January 2004. Exploration and Production - International Far East Thailand: Demand for natural gas from the Company's fields has been strong as a result of reduced production from adjacent fields operated by other companies. This temporary spike in demand for the Company's production has now returned to normal levels as adjacent fields operated by other companies solved their delivery problems. The Company signed a heads of agreement with PTT Public Co., Ltd. ("PTT"), which is intended to amend and extend two of Unocal's gas sales contracts, while increasing gross contracted sales volumes from 740 MMcf/d to 850 MMcf/d in 2006, and to 1,240 MMcf/d in subsequent years. The Company and its partners also signed an agreement in October 2003 with PTT to increase gross contracted gas sales volumes from the Pailin field by nearly 12-percent to 368 MMcf/d. The Company expects higher average liquids production, with the full-year effect of crude oil production from its Yala field. In September 2003, the Company filed notice with the government of Thailand seeking approval for the second phase of development of the Company's offshore oil fields. The second phase is designed to double gross oil production from the Yala and Plamuk fields to 40,000 barrels per day. Current plans call for the required new facilities to be installed by mid-2005 with start-up of new production commencing shortly thereafter. The Company has a 71.25 percent working interest in the Yala field (62 percent net of royalty). The Company will continue to explore for and develop additional oil and gas resources in the Gulf of Thailand and support the efforts of PTT Exploration and Production PLC ("PTTEP") in the development of the Arthit gas field in the gulf. The Company has a 16-percent working interest in the Arthit gas field. Indonesia: The Company's Unocal Ganal, Ltd. ("Unocal Ganal"), subsidiary has made a significant gas-condensate and oil discovery on the deepwater Gehem prospect in the Ganal production-sharing contract area, 3.5 miles south of the Ranggas field offshore East Kalimantan, Indonesia. The Gehem-1 well encountered 617 feet of net gas and gas-condensate pay and 18 feet of net oil pay. The well was drilled in 5,981 feet of water to a total vertical depth of 15,241 feet. More than 400 feet of the net pay was in a stratigraphic interval that had not been penetrated during drilling in the nearby Ranggas field. The results of the Gehem-1 well indicate possibly significant oil and condensate accumulations in the deeper untested trend underlying the existing Gada, Gula, and Ranggas discoveries. The Company expects to complete the Gehem-2 appraisal well during the fourth quarter. Unocal Ganal is the operator of the Ganal PSC and holds an 80-percent working interest. The Company's new production from the deepwater West Seno oil and gas field came on line in early August 2003. The Company has experienced facility related start-up and processing issues, some of which have been corrected and others are still being addressed. Gross production for the third quarter from West Seno averaged more than 5,400 BOE per day. The Company had expected average production of nearly 20,000 BOE per day from West Seno in the third quarter. The Company will continue to drill additional development wells, which are expected to ramp up gross production from the field up to 15,000 to 20,000 BOE per day by year-end. The Company expects to achieve peak gross production rates of 35,000 to 45,000 BOE per day from Phase 1, rising to 55,000 to 65,000 BOE per day when Phase 2 is completed. Gross development costs for the first phase are expected to be approximately $500 million with an additional $240 million for the second phase (Unocal's net share is expected to be approximately $450 million and $215 million for the first and second phases, respectively). The Company and its co-venturer completed financing arrangements for a portion of the total costs through the Overseas Private Investment Corporation in late March 2003 through two loans. One loan is for $300 million and covers the first phase, and the other loan is for $50 million and is for the second phase. The loan associated with the second phase is still subject to a final construction contract being obtained. -52- The Company's Unocal Rapak, Ltd. ("Unocal Rapak"), subsidiary successfully completed drilling the Ranggas Selatan-1 appraisal well, extending the Ranggas field to the south on the Rapak production-sharing contract area. The Selatan-1 well was drilled to a true vertical depth of 10,243 feet, and penetrated 187 feet of net oil pay and 258 feet of net gas pay in several zones of high quality reservoir rock. The Selatan-1 well was drilled 1 mile south of the Ranggas-1 discovery well and 5.7 miles north of the Gehem-1 well. The Company is conducting conceptual engineering studies for the possible development of the Ranggas field. The Company is planning to have the Ranggas development project ready for government approval by early next year. The Company plans to move the Ranggas project along while assessing the deep potential and options for co-development with the Gehem field. Unocal Rapak is operator of the Rapak PSC area and holds an 80-percent working interest. The Company is currently drilling a second deep appraisal well in the Sadewa field in the East Kalimantan PSC area to test for oil. The Sadewa discovery well was drilled in 2002 and found both natural gas and oil. The oil play found near the bottom of the well provided encouragement for deeper oil potential that could not be fully evaluated at the time. The first appraisal well also found both natural gas and oil. The Company holds a 50-percent working interest in the well. China: The Company has worked with China National Offshore Oil Corporation ("CNOOC"), China New Star Petroleum Corporation, the Shanghai Municipality and the State Planning Commission to promote appraisal and development of natural gas resources in the Xihu Trough, off the coast of Shanghai, in the East China Sea. Unocal believes the area could contain significant amounts of recoverable natural gas. The Company signed five PSCs in 2003 to explore and develop natural gas resources. The project area covers nearly 5.4 million acres in approximately 300 feet of water. The project scope includes appraisal and development of discovered fields, as well as further exploration potential. CNOOC will be the operator of all five contract areas. The appraisal and exploration work for Phase 1 of the project will focus on development of the resources in and around the 173,000-acre Chunxiao Block. The near-term work program involves drilling appraisal and exploration wells to prove additional resources sufficient to warrant a first phase of commercial development. Natural gas from the project would be delivered by pipeline 220 miles to the Zhejiang province and Shanghai area markets. Liquids would be transported by pipeline to the Pinghu offshore development that is 37 miles from the proposed Xihu central processing platform. The Chinese government has encouraged the project participants to bring production on stream as soon as possible, targeting the middle of 2005. Production is expected to reach 250 MMcf/d within two years of first production. The Company holds a 20-percent working interest in the five PSCs. Other International Azerbaijan: The Azerbaijan International Operating Company ("AIOC") consortium, in which the Company has a 10.28% working interest, is on track with its development of Phases I and II of the offshore Azeri field in the Azeri-Chirag-Gunashli structure in the Azerbaijan sector of the Caspian Sea. The project is under construction, with Phase 1 approximately 70 percent complete and on schedule with first oil from the Phase 1 Central Azeri platform expected early in 2005. A third phase is in early engineering and is expected to be approved in 2004. Gross production from the combined phases, plus the currently producing Early Oil Project in the Chirag Field, is forecasted to be over 1 MMBbl/d (gross) by 2009. This forecast is contingent upon the completion of the BTC pipeline project and the general political risks inherent to the region. The multi-country nature of this pipeline along with multinational participation in the consortium, in addition to project financing from international lending institutions like the IFC and EBRD and expected loan packages from several export credit agencies, should help to mitigate the political risk. -53- Bangladesh: Natural gas sales in the country have expanded and the Company has completed work on amending agreements to increase the Take-or-Pay volume for natural gas sold to Petrobangla, the state oil and gas company. The new agreement increased the Take-or-Pay volume of natural gas from 80 MMcf/d to 100 MMcf/d gross. In addition, the Company signed agreements with Petrobangla to develop and produce natural gas from the Moulavi Bazar field located on Block 14. Under the agreement, the Company expects to produce 70 to 100 MMcf/d of natural gas beginning in the first quarter of 2005. Total development cost of the project is estimated at approximately $45 million. The Company also continues to work with the government of Bangladesh and Petrobangla to develop additional reserves and export natural gas to markets in neighboring India. At October 31, 2003, the Company's business unit in Bangladesh had a gross receivable balance of approximately $25 million relating to invoices billed for natural gas and condensate sales to Petrobangla. Approximately $21 million of the outstanding balance represented past due amounts and accrued interest for invoices covering March through September 2003. Generally, invoices, when paid, have been paid in full. The Company is working with Petrobangla and the government of Bangladesh regarding the collection of the outstanding receivables. Myanmar: In late July 2003, the President of the United States signed the Burmese Freedom and Democracy Act of 2003 ("the Act") and issued Executive Order 13310 expanding existing U.S. sanctions against Myanmar. It appears that this latest action will not have a material adverse effect on revenues the Company receives from its interests in Myanmar. Midstream Construction of the BTC pipeline is progressing with about 40 percent of the project completed as of September 30, 2003. The pipeline project is planned to have a crude oil throughput capacity of 1 million Bbl/d. Completion of the pipeline is expected in late 2004 at an overall estimated cost of approximately $3 billion and is expected to be in operation in early 2005. The Company has an 8.9 percent interest and is one of eleven shareholders in the BTC pipeline project. The pipeline company anticipates financing up to 70 percent of the pipeline's cost. The Company signed a bridge financing agreement in the third quarter whereby the Company, along with several other participants will provide short-term financing to the State Oil Company of the Azerbaijan Republic ("SOCAR") for purposes of funding SOCAR's share of BTC pipeline expenditures until proceeds from the project financing are disbursed. The Company's 14.24% share of this financing is anticipated to amount to less than $50 million with payback, including interest, expected in the first half of 2004. In early November 2003 the IFC and EBRD approved packages of $250 million and $125 million, respectively, for the pipeline project. It is anticipated that with the IFC and EBRD approved loan packages to the project that export-import banks and other commercial lenders are likely to approve lending to the project. The Kenai Kachemak Pipeline in Alaska was completed and is transporting natural gas from Ninilchik to Kenai, where it is tied into the existing gas grid serving south central Alaska. Geothermal and Power Operations In the Philippines, the Company's wholly-owned subsidiary Philippine Geothermal, Inc. and two government-owned entities, the National Power Corporation and the Power Sector Assets and Liabilities Management Corporation signed a compromise settlement agreement covering the definitive terms of settlement in March 2003. The parties are continuing the process of securing all necessary Philippine government and court approvals of the settlement. The Company's Unocal North Sumatra Geothermal, Ltd. subsidiary has agreed to sell its rights and interest in the Sarulla geothermal project on the island of Sumatra, Indonesia to the Indonesian state electricity company. The anticipated sales price is $60 million. The transaction is expected to close by the end of 2003, and the Company expects to record a gain of approximately $15 million on the transaction (see note 12 to the consolidated financial statements in Item 1 of this report). -54- Corporate & Other In October 2003, the Company repurchased a portion of its outstanding note issues both in a tender offer and open market purchases. Overall, the Company repurchased $290 million of debt principal at a premium of approximately $32 million in October and November. This activity coupled with debt repurchasing that occurred in late September brought the overall total of debt repurchases, since September 1, to $300 million at a premium of $34 million. FUTURE ACCOUNTING CHANGES FASB Interpretation No. 46: Effective January 1, 2003, the Company adopted the disclosure provisions of FASB Interpretation No. 46, "Consolidation of Variable Interest Entities". The Company, as encouraged by the pronouncements of the FASB, partially adopted the recognition (i.e., consolidation) requirements of the Interpretation effective July 1, 2003. (See notes 2 and 14 to the consolidated financial statements in Item 1 of this report). In addition, because of the complexities of this rule and the FASB deferral, as set for in FASB Staff Position No. FIN 46-6, of mandatory adoption until December 31, 2003, the Company continues to review and may find additional material interests in entities which could require recognition or disclosure in the financial statements. Consistent with SFAS No. 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies," costs of acquiring oil and gas drilling rights have been classified as tangible assets in property, plant and equipment. The Company understands the staff of the SEC believes SFAS No. 19 does not provide guidance as to whether these assets should be classified as tangible or intangible and therefore believe SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and Other Intangible Assets," would require that drilling rights be classified as an intangible asset. The SEC has requested the FASB to address this perceived conflict within the related FASB statements. The resolution of this issue will have no impact on the Company's results of operations. If the FASB concurs with the SEC, it would result in additional disclosures and a balance sheet reclassification of these assets from Properties-net to Intangible Assets. Other proposed accounting changes considered from time to time by the FASB, the SEC and the United States Congress could materially impact the Company's reported financial position and results of operations. -55- ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. Market risk generally represents the risk that losses may occur in the values of financial instruments as a result of changes in interest rates, foreign currency exchange rates and commodity prices. As part of its overall risk management strategies, the Company uses derivative financial instruments to manage and reduce risks associated with these factors. The Company also trades hydrocarbon derivative instruments, such as futures contracts, swaps and options to exploit anticipated opportunities arising from commodity price fluctuations. The Company determines the fair values of its derivative financial instruments primarily based upon market quotes of exchange traded instruments. Most futures and options contracts are valued based upon direct exchange quotes or industry published price indices. Some instruments with longer maturity periods require financial modeling to accommodate calculations beyond the horizons of available exchange quotes. These models calculate values for outer periods using current exchange quotes (i.e., forward curve) and assumptions regarding interest rates, commodity and interest rate volatility and, in some cases, foreign currency exchange rates. While the Company feels that current exchange quotes and assumptions regarding interest rates and volatilities are appropriate factors to measure the fair value of its longer termed derivative instruments, other pricing assumptions or methodologies may lead to materially different results in some instances. Interest Rate Risk - From time to time the Company temporarily invests its excess cash in short-term interest-bearing securities issued by high-quality issuers. Company policies limit the amount of investment in securities of any one financial institution. Due to the short time the investments are outstanding and their general liquidity, these instruments are classified as cash equivalents in the consolidated balance sheet and do not represent a material interest rate risk to the Company. The Company's primary market risk exposure to changes in interest rates relates to the Company's long-term debt obligations. The Company manages its exposure to changing interest rates principally through the use of a combination of fixed and floating rate debt. Interest rate risk sensitive derivative financial instruments, such as swaps or options may also be used depending upon market conditions. The Company evaluated the potential effect that near term changes in interest rates would have had on the fair value of its interest rate risk sensitive financial instruments at September 30, 2003. Assuming a ten percent decrease in the Company's weighted average borrowing costs at September 30, 2003, the potential increase in the fair value of the Company's debt obligations and associated interest rate derivative instruments, including the debt obligations and associated interest rate derivative instruments of its subsidiaries, would have been approximately $94 million at September 30, 2003. Foreign Exchange Rate Risk - The Company conducts business in various parts of the world and in various foreign currencies. To limit the Company's foreign currency exchange rate risk related to operating income, foreign sales agreements generally contain price provisions designed to insulate the Company's sales revenues against adverse foreign currency exchange rates. In most countries, energy products are valued and sold in U.S. dollars and foreign currency operating cost exposures have not been significant. In other countries, the Company is paid for product deliveries in local currencies but at prices indexed to the U.S. dollar. These funds, less amounts retained for operating costs, are converted to U.S. dollars as soon as practicable. The Company's Canadian subsidiaries are paid in Canadian dollars for their crude oil and natural gas sales and have Canadian dollar denominated debt outstanding. From time to time the Company may purchase foreign currency options or enter into foreign currency swap or foreign currency forward contracts to limit the exposure related to its foreign currency debt or other obligations. At September 30, 2003, the Company had various foreign currency swaps and foreign currency forward contracts outstanding related to operations in Thailand and The Netherlands. The Company evaluated the effect that near term changes in foreign exchange rates would have had on the fair value of the Company's combined foreign currency position related to its outstanding foreign currency denominated debt, foreign currency swaps and forward contracts. Assuming an adverse change of ten percent in foreign exchange rates at September 30, 2003, the potential decrease in fair value of the foreign-currency denominated debt, foreign currency swaps and foreign currency forward contracts of the Company and its subsidiaries would have been approximately $25 million at September 30, 2003. -56- Commodity Price Risk - The Company is a producer, purchaser, marketer and trader of certain hydrocarbon commodities such as crude oil and condensate, natural gas and refined products and is subject to the associated price risks. The Company uses hydrocarbon price-sensitive derivative instruments ("hydrocarbon derivatives"), such as futures contracts, swaps, collars and options to mitigate its overall exposure to fluctuations in hydrocarbon commodity prices. The Company may also enter into hydrocarbon derivatives to hedge contractual delivery commitments and future crude oil and natural gas production against price exposure. The Company also actively trades hydrocarbon derivatives, primarily exchange regulated futures and options contracts, subject to internal policy limitations. The Company uses a variance-covariance value at risk model to assess the market risk of its hydrocarbon derivatives. Value at risk represents the potential loss in fair value the Company would experience on its hydrocarbon derivatives, using calculated volatilities and correlations over a specified time period with a given confidence level. The Company's risk model is based upon current market data and uses a three-day time interval with a 97.5 percent confidence level. The model includes offsetting physical positions for any existing hydrocarbon derivatives related to the Company's fixed price pre-paid crude oil and pre-paid natural gas sales. The model also includes the Company's net interests in its subsidiaries' crude oil and natural gas hydrocarbon derivatives and forward sales contracts. Based upon the Company's risk model, the value at risk related to hydrocarbon derivatives held for hedging purposes was approximately $37 million at September 30, 2003. The value at risk related to hydrocarbon derivatives held for non-hedging purposes was approximately $1 million at September 30, 2003. In order to provide a more comprehensive view of the Company's commodity price risk, a tabular presentation of open hydrocarbon derivatives is also provided. The following table sets forth the future volumes and price ranges of hydrocarbon derivatives held by the Company at September 30, 2003, along with the fair values of those instruments. -57-
Open Hydrocarbon Hedging Derivative Instruments (a) (Thousands of dollars) Fair Value Asset 2003 2004 2005 2006 2007-2008 (Liability) (b)(c) - ------------------------------------------------------------------------------------------------------------------------------------ Natural Gas Futures Positions Volume (MMBtu) (1,900,000) (6,840,000) 30,000 - - $ 14,976 Average price, per MMBtu $ 5.66 $ 5.84 $ 5.01 - ------------------------------------------------------------------------------------------------------------------------------------ Natural Gas Swap Positions Pay fixed price Volume (MMBtu) 5,514,500 16,205,000 8,793,000 7,218,000 14,459,000 $ 57,231 Average swap price, per MMBtu $ 4.77 $ 4.12 $ 2.84 $ 2.42 $ 2.50 Receive fixed price Volume (MMBtu) 11,590,000 33,790,000 25,550,000 - - $ 18,321 Average swap price, per MMBtu $ 5.75 $ 5.28 $ 4.63 - ------------------------------------------------------------------------------------------------------------------------------------ Natural Gas Basis Swap Positions Volume (MMBtu) - - - - - $ 22 Average price received, per MMBtu Average price paid, per MMBtu - ------------------------------------------------------------------------------------------------------------------------------------ Natural Gas Collar Positions Volume (MMBtu) 5,666,000 268,500 - - - $ (3,032) Average ceiling price, per MMBtu $ 4.50 $ 5.45 Average floor price, per MMBtu $ 3.77 $ 2.82 - ------------------------------------------------------------------------------------------------------------------------------------ Natural Gas Option Call Volume (MMBtu) - - - - - $ (200) Average Call price $ - - ------------------------------------------------------------------------------------------------------------------------------------ Crude Oil Future position Volume (Bbls) (2,460,000) (1,200,000) - - - $ 11,884 Average price, per Bbl $ 30.55 $ 29.37 - ------------------------------------------------------------------------------------------------------------------------------------ Crude Oil Option (Over The Counter) Put Volume (Bbls) (400,000) (720,000) - - - $ 858 Average price, per Bbl $ 24.00 $ 20.00 - ------------------------------------------------------------------------------------------------------------------------------------ Crude Oil Collar Positions Volume (Bbls) 437,000 810,000 - - - $ (1,607) Average ceiling price, per Bbl $ 32.00 $ 28.16 Average floor price, per Bbl $ 27.15 $ 23.41 ==================================================================================================================================== (a) Positions reflect long (short) volumes. (b) Net claims against counterparties with non-investment grade credit ratings are immaterial. (c) Includes $4,948 thousand in assumed liabilities which were capitalized as acquisition costs.
-58-
Open Hydrocarbon Non-Hedging Derivative Instruments (a) (Thousands of dollars) 2003 2004 Fair Value Asset (Liability) (b) --------------- --------------- ------------------------ Natural Gas Futures Positions Volume (MMBtu) 1,320,000 - $(2,402) Average price, per MMBtu $ 5.35 - ------------------------------------------------------------------------------------------------ Natural Gas Swap Positions Pay fixed price Volume (MMBtu) 1,215,000 - $(2,694) Average swap price, per MMBtu $ 5.25 Receive fixed price Volume (MMBtu) 1,084,088 95,438 $(2,098) Average swap price, per MMBtu $ 5.16 $ 2.30 - ------------------------------------------------------------------------------------------------ Natural Gas Basis Swap Positions Volume (MMBtu) 5,520,000 - $ 783 Average price received, per MMBtu $ 4.64 Average price paid, per MMBtu $ 4.54 - ------------------------------------------------------------------------------------------------ Natural Gas Spread Swap Positions Volume (MMBtu) 1,985,000 3,040,000 $ 3,965 Average price received, per MMBtu $ 0.99 $ 0.38 Average price paid, per MMBtu $ 0.72 $ 1.51 - ------------------------------------------------------------------------------------------------ Natural Gas Option (Listed & OTC) Call Volume (MMBtu) 5,150,000 - $ (473) Average Call price $ 6.10 Call Volume (MMBtu) (15,990,000) (1,940,000) $ 5,020 Average Call price $ 6.05 $ 5.79 Put Volume (MMBtu) 4,480,000 4,870,000 $(1,340) Average Put Price $ 4.62 $ 4.09 Put Volume (MMBtu) (10,910,000) (455,000) $ 2,128 Average Put Price $ 4.41 $ 4.30 - ------------------------------------------------------------------------------------------------ Natural Gas Spread Option (Over the Counter) NYMEX / IFERC (c) Call Volume (MMBtu) (300,000) (470,000) $ 0 Average Strike price $ 0.75 $ 2.00 Put Volume (MMBtu) (1,000,000) - $ 25 Average Strike price $ 0.25 $ - - ------------------------------------------------------------------------------------------------ Crude Oil Future position Volume (Bbls) 100,000 - $ (52) Average price, per Bbl $ 28.34 - ------------------------------------------------------------------------------------------------ Crude Oil Option Call Volumes (Bbls) 1,135,000 - $ (165) Average price, per Bbl $ 32.77 Call Volumes (Bbls) (600,000) - $ 227 Average price, per Bbl $ 33.00 Put Volume (Bbls) 700,000 - $ (171) Average price, per Bbl $ 27.64 Put Volume (Bbls) (700,000) - $ 156 Average price, per Bbl $ 27.07 - ------------------------------------------------------------------------------------------------ Crude Oil Swap Positions Pay fixed price Volume (Bbls) 1,450,000 2,300,000 $ (507) Average swap price, per Bbl $ 27.49 26.13 Receive fixed price Volume (Bbls) 1,450,000 2,500,001 $ 999 Average swap price, per Bbl $ 27.06 $ 25.78 - ------------------------------------------------------------------------------------------------ (a) Positions reflect long (short) volumes. (b) Includes $3,464 thousand net claims against counterparties with non-investment grade credit ratings. (c) Prices quoted from the New York Mercantile Exchange (NYMEX) and Inside FERC Gas Report (IFERC).
-59- ITEM 4. CONTROLS AND PROCEDURES As of the end of the period covered by this report, the Company carried out an evaluation of the effectiveness of the design and operation of the Company's disclosure controls and procedures pursuant to Rule 13a-15(e) of the Securities Exchange Act of 1934. Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company's disclosure controls and procedures are effective in timely identifying material information potentially required to be included in the Company's SEC filings. There was no change in the Company's internal control over financial reporting that occurred during the third quarter of 2003 that has materially affected, or is reasonably likely to materially affect, the Company's internal control over financial reporting. Section 404 of the Sarbanes-Oxley Act of 2002 will require the Company to include an internal control report with its 2004 annual report on Form 10-K. The internal control report must assert (i) management's responsibilities to establish and maintain adequate internal control over financial reporting and (ii) management's assessment of the effectiveness of this internal control as of the end of the most recent fiscal year. The Company's auditors will, in 2004, be required to audit, and report on, these assertions. In order to achieve compliance with Section 404 within the statutory period, management has formed a steering committee and adopted a detailed project work plan to assess the adequacy of the Company's internal controls, remediate any control weaknesses that may be identified and validate through testing that controls are functioning as documented. As a result of this initiative, the Company may make changes in its internal controls from time to time during the period prior to December 31, 2004. -60- PART II - OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS. See the information with respect to certain legal proceedings pending or threatened against the Company previously reported in Item 3 of Unocal's Annual Report on Form 10-K for the year ended December 31, 2002, and in Item 1 of Part II of Unocal's Quarterly Report on Form 10-Q for the quarterly periods ended March 31 and June 30, 2003. There is incorporated by reference: the information regarding the environmental remediation reserve and possible additional remediation costs in notes 16 and 17 to the consolidated financial statements in Item 1 of Part I of this report; the discussion of such amounts in the Environmental Matters section of Management's Discussion and Analysis in Item 2 of Part I; and the information regarding certain litigation and claims, tax matters and other contingent liabilities in note 17 to the consolidated financial statements. Certain Environmental Matters Involving Civil Penalties The Environmental Protection Agency ("EPA") and Unocal have entered into civil settlements regarding the EPA's claims that Unocal violated the National Pollutant Discharge Elimination System (NPDES) general permit concerning the discharge of produced water and sanitary wastes into the Cook Inlet. On May 8, 2003, Unocal and the EPA executed Consent Agreements with respect to alleged violations at 11 facilities. The settlements were subject to public comment before final approval. On September 29, 2003, the Consent Agreements for ten facilities received final approval, after those for three facilities were amended to incorporate an additional 120 alleged violations. Unocal and the EPA have entered into an amended Consent Agreement for one facility which remains subject to public comment before final approval. The outstanding Consent Agreement has been amended to incorporate an additional 61 alleged violations. Most of the additional alleged violations include a monthly reporting period, and therefore qualify as violations for each day of the entire standard 30-day month. The total amount of the fine imposed pursuant to the settlements is $531,875, of which Unocal will pay $327,991 and the remainder will be paid by other working interest owners in the affected facilities. ITEM 5. OTHER INFORMATION. Effective October 1, 2003, the Company's Board of Directors named Samuel H. Gillespie III as senior vice president, chief legal officer and general counsel. Mr. Gillespie succeeds Charles O. Strathman and Timothy H. Thomas who had been serving as chief legal officer and general counsel, respectively, on an interim basis. Both Messrs. Strathman and Thomas will resume their former positions as vice president, Law, during a transition period over the next several months. Mr. Gillespie was also named as Corporate Secretary, succeeding Brigitte M. Dewez. Mr. Gillespie joins Unocal from the Washington, D.C., office of the law firm of Skadden, Arps, Slate, Meagher and Flom, where he advised energy clients and worked on a variety of international projects. Previously, he was senior vice president and general counsel with Mobil Corporation. -61- ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K. (a) Exhibits: The Exhibit Index on page 64 of this report lists the exhibits that are filed as part of this report. (b) Reports on Form 8-K: Filed during the third quarter of 2003: (1) Current Report on Form 8-K, dated and filed July 14, 2003, for the purpose of reporting, under Item 5, the Company's agreement to sell its rights and interest in the Sarulla geothermal project on the island of Sumatra in Indonesia. (2) Current Report on Form 8-K, dated July 15, 2003, and filed July 16, 2003, for the purpose of reporting, under Item 5 and Item 7, the Company's filing of an amended Schedule 13D with respect to the Company's interest in Tom Brown, Inc. (3) Current Report on Form 8-K, dated July 23, 2003, and filed July 24, 2003, for the purpose of reporting, under Item 5, the Company's discovery on the deepwater Gehem prospect, offshore East Kalimantan, Indonesia. (4) Current Report on Form 8-K, dated July 29, 2003, and filed July 31, 2003, for the purpose of reporting, under Item 5, the Company's second quarter and six months earnings results, other related information and the Company's 2003 outlook. (5) Current Report on Form 8-K, dated September 16, 2003, and filed September 18, 2003, for the purpose of reporting, under Item 5, the Company's sale of common shares held in Tom Brown, Inc. (6) Current Report on Form 8-K, dated September 21, 2003, and filed September 23, 2003, for the purpose of reporting, under Item 5, the Company agreement to sell 70 properties in the Gulf of Mexico and onshore Louisiana to Forest Oil Corporation. Filed during the fourth quarter of 2003 to the date hereof: (1) Current Report on Form 8-K, dated October 3, 2003, and filed October 6, 2003, for the purpose of reporting, under Item 5, the Company's production forecast for the third and fourth quarters of 2003. (2) Current Report on Form 8-K, dated October 29, 2003, and filed November 3, 2003, for the purpose of reporting under Item 5, the Company's third quarter and nine months earnings results, other related information, the Company's outlook for the remainder of 2003 and a discovery in the deepwater Gulf of Mexico. -62- SIGNATURE Pursuant to the requirements 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. UNOCAL CORPORATION (Registrant) Dated: November 14, 2003 By: /s/JOE D. CECIL --------------------- Joe D. Cecil Vice President and Comptroller (Duly Authorized Officer and Principal Accounting Officer) -63- EXHIBIT INDEX 10 Employment Agreement, effective as of October 1, 2003, by and between Unocal and Samuel H. Gillespie III. 12.1 Statement regarding computation of ratio of earnings to fixed charges of Unocal Corporation for the nine months ended September 30, 2003 and 2002. 12.2 Statement regarding computation of ratio of earnings to fixed charges of Union Oil Company of California for the nine months ended September 30, 2003 and 2002. 31 Certifications Pursuant to 18 U.S.C Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 32 Certifications Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. Copies of exhibits will be furnished upon request. Requests should be addressed to the Corporate Secretary. -64- EX-10 3 q32003_ex10.txt SAM GILLESPIE Exhibit 10 UNOCAL EMPLOYMENT AGREEMENT This employment agreement (the "Agreement") is made effective as of October 1, 2003 by and between Unocal Corporation, a Delaware corporation (the "Company") and Samuel H. Gillespie, III ("Employee"). In consideration of the mutual promises and agreements set forth herein, the Company and Employee agree as follows: 1. Term. ---- 1.1 The term of this Agreement (the "Term") shall commence on October 1, 2003 and shall be for two (2) years, subject to earlier termination in accordance with the provisions of Section 4 hereinbelow. If the Agreement has not been subject to early termination in accordance with the provisions of Section 4 hereinbelow, beginning on October 1, 2003 and on each day thereafter, the Term shall automatically be extended for an additional day unless the Company notifies Employee in writing that it does not wish to further extend the Term. Notwithstanding the foregoing, this Agreement shall end automatically and without additional notice on the date of the Company's Annual Meeting of Shareholders that next follows the date of Employee's sixty-fifth (65th) birthday. 2. Position and Title. ------------------ 2.1 The Company on behalf of itself and its affiliates and subsidiaries hereby employs Employee as Chief Legal Officer & General Counsel and Employee hereby accepts such employment. 2.2 Employee shall devote substantially all of his efforts on a full time basis to the business and affairs of the Company and shall not engage in any business or perform any services in any capacity whatsoever adverse to the interests of the Company. 2.3 Employee shall at all times faithfully, industriously, and to the best of his ability, experience, and talents, perform all of the duties of his position. 3. Compensation. ------------ 3.1 As of the date of this Agreement, Employee's annual base salary is $425,000. Employee's base salary and performance shall be reviewed periodically at intervals approved by the Management Development and Compensation Committee of the Board of Directors of the Company (the "Committee"), and Employee's base salary may be increased from time to time based on merit or such other consideration as the Committee may deem appropriate. 3.2 During the Term, Employee shall participate in all of the Company's incentive plans, benefit plans and perquisites, and in any new or successor incentive plans, benefit plans and perquisites, that are generally provided to executives of the Company with a level of responsibility and stature comparable to Employee. Performance goals, award opportunity, benefit levels, and administrative guidelines for such plans shall be subject to review and approval by the Committee. -1- 4. Termination of Employment. ------------------------- 4.1 During the Term, the Company may terminate Employee's employment herein at any time for Cause or as a result of a material breach by Employee of his obligations under this Agreement, provided however that, except in the case of conviction of a felony, the Company shall provide Employee with not less than sixty (60) days prior written notice describing the behavior or conduct which is alleged by the Company to constitute Cause, and Employee shall be provided with reasonable opportunity to correct such behavior or conduct within the notice period. For purposes of this Agreement, Cause shall be defined as any or all of the following: (1) Conduct or action by Employee which, in the opinion of a majority of the Board of Directors, is materially harmful to the Company; (2) Willful failure by Employee to follow an order of the Board, except in such case where the Employee believes in good faith that following such order would be materially detrimental to the interests of the Company; (3) Employee's conviction of a felony. 4.2 In the event that Employee's employment is terminated by the Company for any reason other than those set forth in Paragraph 4.1 hereinabove, or, (a) Employee's annual base salary is reduced below the amount stated in Paragraph 3.1 hereinabove (unless such reduction is part of an across the board reduction affecting all Company executives with a comparable level of responsibility, title or stature), or (b) Employee is removed from or denied participation in incentive plans, benefit plans, or perquisites generally provided by the Company to other executives with a comparable level of responsibility, title or stature, or (c) Employee's target incentive opportunity, benefits or perquisites are reduced relative to other executives with comparable responsibility, title or stature, or (d) Employee is assigned duties or obligations inconsistent with his position with the Company or (e) there is a significant change in the nature and scope of Employee's authority or his overall working environment, or (f) Employee's work location following a Change In Control would result in an increase in his or her one way commute by at least 50 miles from the existing residence, such event shall be considered a Termination Without Cause. 4.3 In the event of Employee's Termination Without Cause at any time during the Term of this Agreement, then: (1) The Company shall pay Employee a lump-sum severance amount within thirty (30) days following Termination Without Cause equal to two (2) times the sum of (a) the higher of the Employee's annual base salary at the time of Termination Without Cause or the annual base salary stated in Paragraph 3.1 hereinabove, and (b) the annual target Bonus applicable to Employee as of the beginning of the calendar year in which such Termination Without Cause occurs. Such sum shall be reduced by the amount of any Unocal Employee Redeployment Program and Unocal Termination Allowance benefits payable to Employee; and further reduced by any Change of Control enhancements (determined by the increase in the lump sum amounts payable to Employee) under the Unocal Retirement Plan and the non-qualified retirement plans of the Company. (2) The Company shall provide for Employee to receive medical, dental, life, and disability insurance coverage for two (2) years following Termination Without Cause at levels and a net cost to Employee comparable to that provided to Employee immediately prior to Employee's Termination Without Cause. In lieu of the foregoing continued benefits, the Company in its sole discretion may elect to pay the Employee the sum of $25,000 (twenty-five thousand U.S. Dollars). (3) The Company shall pay Employee an additional lump-sum severance amount within thirty (30) days following Employee's Termination Without Cause equal to two (2) times the base salary used to determine the lump-sum severance benefit in paragraph 4.3(1) hereinabove, multiplied by 6% (.06). -2- 4.4 In the event that during the Term of this Agreement Employee should voluntarily resign from the Company, should terminate employment with the Company due to death, permanent disability or incapacitation, or is terminated by the Company for Cause or for a material breach by Employee of his obligations under this Agreement, then Employee shall not be entitled to any of the termination benefits provided for in Paragraph 4.3 hereinabove, and the Term of the Agreement shall immediately end. 4.5 Employee shall not be obligated to seek other employment or take any other action by way of mitigation of the amounts payable to Employee under any provisions of this Agreement. 5. Change of Control. ----------------- 5.1 In the event of a Change of Control of the Company at any time during the Term of this Agreement, then: (1) In the event of Employee's Termination Without Cause within a period of twenty-four (24) months following the date of a Change of Control, Employee shall be entitled to the termination benefits described in Paragraph 4.3 hereinabove plus the benefit described in Section 5.1(2) below. (2) The Employee shall be entitled to an amount equal to the increase in the lump sum value of Employee's Unocal Retirement Plan and non-qualified retirement plans of the Company if three years were added to Employee's benefit service and age thereunder. Such amount shall be payable hereunder notwithstanding Section 4.3(1) above. 5.2 For the purpose of this Agreement, a "Change of Control" shall mean: (a) The acquisition by any individual, entity or group (within the meaning of Section 13(d)(3) or 14(d)(2) of the Securities Exchange Act of 1934, as amended (the "Exchange Act")(a "Person") of beneficial ownership (within the meaning of Rule 13d-3 promulgated under the Exchange Act) of 20% or more of either (i) the then outstanding shares of common stock of the Company (the "Outstanding Company Common Stock") or (ii) the combined voting power of the then outstanding voting securities of the Company entitled to vote generally in the election of directors (the "outstanding Company Voting Securities"); provided, however, that for purposes of this subsection (a), the following acquisitions shall not constitute a Change of Control: (i) any acquisition directly from the Company, (ii) any acquisition by the Company, (iii) any acquisition by an employee benefit plan (or related trust) sponsored or maintained by the Company or any corporation controlled by the Company or (iv) any acquisition by any corporation pursuant to a transaction which complies with clauses (i), (ii) and (iii) of subsection (c) of this Section 5.2; or (b) Individuals who, as of the date hereof, constitute the Board (the "Incumbent Board") cease for any reason to constitute at least a majority of the Board; provided, however, that any individual becoming a director subsequent to the date hereof whose election, or nomination for election by the Company's shareholders, was approved by a vote of at least a majority of the directors then comprising the Incumbent Board shall be considered as though such individual were a member of the Incumbent Board, but excluding, for this purpose, any such individual whose initial assumption of office occurs as a result of an actual or threatened election contest with respect to the election or removal of directors or other actual or threatened solicitation of proxies or consents by or on behalf of a Person other than the Board; or -3- (c) Consummation of a reorganization, merger or consolidation or sale or other disposition of all or substantially all of the assets of the Company or the acquisition of assets of another corporation (a "Business Combination"), in each case, unless, following such Business Combination, (i) all or substantially all of the individuals and entities who were the beneficial owners, respectively, of the Outstanding Company Common Stock and Outstanding Company Voting Securities immediately prior to such Business Combination beneficially own, directly or indirectly, more than 50% of, respectively, the then outstanding shares of common stock and the combined voting power of the then outstanding voting securities entitled to vote generally in the election of directors, as the case may be, of the corporation resulting from such Business Combination (including, without limitation, a corporation which as a result of such transaction owns the Company or all or substantially all of the Company's assets either directly or through one or more subsidiaries) in substantially the same proportions as their ownership, immediately prior to such Business Combination of the Outstanding Company Common Stock and Outstanding Company Voting Securities, as the case may be, (ii) no Person (excluding any corporation resulting from such Business Combination or any employee benefit plan (or related trust) of the Company or such corporation resulting from such Business Combination) beneficially owns, directly or indirectly, 20% or more of, respectively, the then outstanding shares of common stock of the corporation resulting from such Business Combination or the combined voting power of the then outstanding voting securities of such corporation except to the extent that such ownership existed prior to the Business Combination and (iii) at least a majority of the members of the board of directors of the corporation resulting from such Business Combination were members of the Incumbent Board at the time of the execution of the initial agreement, or of the action of the Board, providing for such Business Combination; or (d) Approval by the shareholders of the Company of a complete liquidation or dissolution of the Company. 5.3 Certain Additional Payments by the Company may be due as follows (a) Anything in this Agreement to the contrary notwithstanding and except as set forth below, in the event it shall be determined that any payment or distribution by the Company or its affiliates to or for the benefit of the Employee (whether paid or payable or distributed or distributable pursuant to the terms of this Agreement or otherwise but determined without regard to any additional payments required under this Section 5.3), (a "Payment") would be subject to the excise tax imposed by Section 4999 of the Code or any interest or penalties are incurred by the Employee with respect to such excise tax (such excise tax, together with any such interest and penalties, are hereinafter collectively referred to as the "Excise Tax"), then the Employee shall be entitled to receive an additional payment (a "Gross-Up Payment") in an amount such that after payment by the Employee of all taxes (including any interest or penalties imposed with respect to such taxes), including, without limitation, any income taxes (and any interest and penalties imposed with respect thereto) and Excise Tax imposed upon the Gross-Up Payment, the Employee retains an amount of the Gross-Up Payment equal to the Excise Tax imposed upon the Payments. Notwithstanding the foregoing provisions of this Section 5.3, if it shall be determined that the Employee is entitled to a Gross-Up Payment, but that the Payments do not exceed 110% of the greatest amount (the "Reduced Amount") that could be paid to the Employee such that the receipt of Payments would not give rise to any Excise Tax, then no Gross-Up Payment shall be made to the Employee and the Payments, in the aggregate, shall be reduced to the Reduced Amount. (b) Subject to the provisions of Section 5.3(c), all determinations required to be made under this Section 5.3, including whether and when a Gross-Up Payment is required and the amount of such Gross-Up Payment and the assumptions to be utilized in arriving at such determination, shall be made by Ernst and Young or such other certified public accounting firm as may be designated by the Employee (the "Accounting Firm") which shall provide detailed supporting calculations both to the Company and the Employee within 15 business days of the receipt of notice from the Employee that there has been a Payment, or such earlier time as is requested by the Company. In the event that the Accounting Firm is serving as accountant or auditor for the individual, entity or group effecting the Change of Control, the Employee shall appoint another nationally recognized accounting firm to make the determinations required hereunder (which accounting firm shall then be referred to as the Accounting Firm hereunder). All fees and expenses of the Accounting Firm shall be borne solely by the Company. Any Gross-Up Payment, as determined pursuant to this Section 5.3, shall be paid by the Company to the Employee within five days of the receipt of the Accounting Firm's determination. Any determination by the Accounting Firm shall be binding upon the Company and the Employee. As a result -4- of the uncertainty in the application of Section 4999 of the Code at the time of the initial determination by the Accounting Firm hereunder, it is possible that Gross-Up Payments which will not have been made by the Company should have been made ("Underpayment"), consistent with the calculations required to be made hereunder. In the event that the Company exhausts its remedies pursuant to Section 5.3(c) and the Employee thereafter is required to make a payment of any Excise Tax, the Accounting Firm shall determine the amount of the Underpayment that has occurred and any such Underpayment shall be promptly paid by the Company to or for the benefit of the Employee. (c) The Employee shall notify the Company in writing of any claim by the Internal Revenue Service that, if successful, would require the payment by the Company of the Gross-Up Payment. Such notification shall be given as soon as practicable but no later than ten business days after the Employee is informed in writing of such claim and shall apprise the Company of the nature of such claim and the date on which such claim is requested to be paid. The Employee shall not pay such claim prior to the expiration of the 30-day period following the date on which it gives such notice to the Company (or such shorter period ending on the date that any payment of taxes with respect to such claim is due). If the Company notifies the Employee in writing prior to the expiration of such period that it desires to contest such claim, the Employee shall: (i) give the Company any information reasonably requested by the Company relating to such claim, (ii) take such action in connection with contesting such claim as the Company shall reasonably request in writing from time to time, including, without limitation, accepting legal representation with respect to such claim by an attorney reasonably selected by the Company, (iii) cooperate with the Company in good faith in order effectively to contest such claim, and (iv) permit the Company to participate in any proceedings relating to such claim; provided, however, that the Company shall bear and pay directly all costs and expenses (including additional interest and penalties) incurred in connection with such contest and shall indemnify and hold the Employee harmless, on an after-tax basis, for any Excise Tax or income tax (including interest and penalties with respect thereto) imposed as a result of such representation and payment of costs and expenses. Without limitation on the foregoing provisions of this Section 5.3(c), the Company shall control all proceedings taken in connection with such contest and, at its sole option, may pursue or forgo any and all administrative appeals, proceedings, hearings and conferences with the taxing authority in respect of such claim and may, at its sole option, either direct the Employee to pay the tax claimed and sue for a refund or contest the claim in any permissible manner, and the Employee agrees to prosecute such contest to a determination before any administrative tribunal, in a court of initial jurisdiction and in one or more appellate courts, as the Company shall determine; provided, however, that if the Company directs the Employee to pay such claim and sue for a refund, the Company shall advance the amount of such payment to the Employee, on an interest-free basis and shall indemnify and hold the Employee harmless, on an after-tax basis, from any Excise Tax or income tax (including interest or penalties with respect thereto) imposed with respect to the such advance or with respect to any imputed income with respect to such advance; and further provided that any extension of the statute of limitations relating to payment of taxes for the taxable year of the Employee with respect to which such contested amount is claimed to be due is limited solely to such contested amount. Furthermore, the Company's control of the contest shall be limited to issues with respect to which a Gross-Up Payment would be payable hereunder and the Employee shall be entitled to settle or contest, as the case may be, any other issue raised by the Internal Revenue Service or any other taxing authority. -5- (d) If, after the receipt by the Employee of an amount advanced by the Company pursuant to Section 5.3(c), the Employee becomes entitled to receive any refund with respect to such claim, the Employee shall (subject to the Company's employing with the requirements of Section 5.3 promptly pay to the Company the amount of such refund (together with any interest paid or credited thereon after taxes applicable thereto). If, after the receipt by the Employee of an amount advanced by the Company pursuant to Section 5.3(c), a determination is made that the Employee shall not be entitled to any refund with respect to such claim and the Company does not notify the Employee in writing of its intent to contest such denial of refund prior to the expiration of 30 days after such determination, then such advance shall be forgiven and shall not be required to be repaid and the amount of such advance shall offset, to the extent thereof, the amount of Gross-Up Payment required to be paid. 6. Covenants. ---------- 6.1 Employee agrees that any and all confidential knowledge or information, including but not limited to customer lists, books, records, data, formulae, specifications, inventions, processes and methods, and developments and improvements, which have been or may be obtained or learned by Employee in the course of his employment with the Company, will be held confidential by Employee, and that Employee shall not disclose the same to any person outside of the Company either during his employment with the Company or after his employment by the Company has terminated. 6.2 Employee agrees that upon termination of his employment with the Company he will immediately surrender and turn over to the Company all books, records, forms, specifications, formulae, data, and all papers and writings relating to the business of the Company and all other property belonging to the Company, it being understood and agreed that the same are the sole property of the Company and that Employee shall not make or retain any copies thereof. 6.3 Employee agrees that all inventions, developments or improvements which he has made or may make, conceive, invent, discover or otherwise acquire during his employment with the Company in the scope of his responsibilities or otherwise shall become the sole property of the Company. 6.4 Employee agrees to provide a release of any claims with respect to termination of his or her employment on such form as requested by the Company upon payment of the sums provided in Section 4.3 above. 7. Miscellaneous Provisions. ------------------------ 7.1 All terms and conditions of this Agreement are set forth herein, and there are no warranties, agreements or understandings, express or implied, except those expressly set forth herein. 7.2 Any modification to this Agreement shall be binding only if evidenced in writing signed by all parties hereto. 7.3 Any notice or other communication required or permitted to be given hereunder shall be deemed properly given if personally delivered or deposited in the United States mail, registered or certified and postage prepaid, addressed to the Company at 2141 Rosecrans Ave., Suite 4000, El Segundo, CA (Attention: General Counsel), or to Employee at his or her most recent home address on file with Company, or at other such addresses as may from time to time be designated in writing by the respective parties. 7.4 The laws of the State of California shall govern the validity of this Agreement, the construction of its terms, and the interpretation of the rights and duties of the parties involved. 7.5 In the event that any one or more of the provisions contained in this Agreement shall for any reason be held to be invalid, illegal or unenforceable, the same shall not affect any other provision of this Agreement, but this Agreement shall be construed as if such invalid, illegal or unenforceable provisions had never been contained herein. 7.6 This Agreement shall be binding upon, and inure to the benefit of, the successors and assigns of the Company and the personal representatives, heirs and legatees of Employee. 7.7 "Bonus" refers to the Unocal Incentive Compensation Plan and any replacement or successor plan thereof. 7.8 Company shall pay 90% (ninety percent) of Employee's out-of-pocket litigation expenses, including reasonable attorney's fees, in connection with any judicial proceeding to enforce this Agreement or construe or determine the validity of this Agreement, whether or not the Employee is successful in such proceeding. 7.9 The term "Company" shall include with respect to employment hereunder, any subsidiary or affiliate of the Company, as well as any successor employer following a Change in Control. IN WITNESS WHEREOF, the parties have executed this Agreement effective as of the date first above written. BY: /s/ CHARLES R. WILLIAMSON ------------------------------------------------------- Charles R. Williamson for the Management Development and Compensation Committee of the Unocal Board of Directors BY: /s/ SAM H. GILLESPIE, III ------------------------------ EMPLOYEE EX-12 4 q32003_ex12-1.txt UNOCAL RATIO Exhibit 12.1
UNOCAL CORPORATION AND CONSOLIDATED SUBSIDIARIES COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES For the Nine Months Ended September 30, ---------------------------- Millions of dollars 2003 2002 - -------------------------------------------------------------------------------- Earnings from continuing operations $ 538 $ 234 Provision for income taxes 448 203 Minority Interests 8 2 Distributions less than earnings from equity investments 12 1 - -------------------------------------------------------------------------------- Earnings subtotal (a) 1,006 440 Fixed charges included in earnings: Interest expense 119 134 Distribution on convertible preferred securities 24 24 Interest portion of rentals (b) 17 14 - -------------------------------------------------------------------------------- Fixed charges subtotal 160 172 Earnings from continuing operations available before fixed charges $1,166 $ 612 ================================================================================ Fixed charges: Fixed charges included in earnings $ 160 $ 172 Capitalized interest 46 33 - -------------------------------------------------------------------------------- Total fixed charges $ 206 $ 205 - -------------------------------------------------------------------------------- Ratio of earnings from operations to fixed charges 5.7 3.0 - -------------------------------------------------------------------------------- (a) Includes pre-tax Impairment of: 86 27 The ratio of earnings, excluding impairment, to fixed charges would be: 6.1 3.1 (b) Calculated as one-third of operating rental expense.
EX-12 5 q32003_ex12-2.txt UNION OIL RATIO Exhibit 12.2
UNION OIL COMPANY OF CALIFORNIA AND CONSOLIDATED SUBSIDIARIES COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES For the Nine Months Ended September 30, ------------------------------- Millions of dollars 2003 2002 - -------------------------------------------------------------------------------- Earnings from continuing operations $ 565 $ 258 Provision for income taxes 455 208 Minority Interests 8 2 Distributions less than earnings from equity investments 12 1 - -------------------------------------------------------------------------------- Earnings subtotal (a) 1,040 469 Fixed charges included in earnings: Interest expense 119 134 Interest portion of rentals (b) 17 14 - -------------------------------------------------------------------------------- Fixed charges subtotal 136 148 Earnings from continuing operations available before fixed charges $1,176 $ 617 ================================================================================ Fixed charges: Fixed charges included in earnings $ 136 $ 148 Capitalized interest 46 33 - -------------------------------------------------------------------------------- Total fixed charges $ 182 $ 181 - -------------------------------------------------------------------------------- Ratio of earnings from operations to fixed charges 6.5 3.4 - -------------------------------------------------------------------------------- (a) Includes pre-tax Impairment of: 86 27 The ratio of earnings, excluding impairment, to fixed charges would be: 6.9 3.6 (b) Calculated as one-third of operating rental expense.
EX-31 6 q32003_ex31.txt 302 CERTIFICATIONS Exhibit 31 CERTIFICATIONS I, Charles R. Williamson, certify that: 1. I have reviewed this quarterly report on Form 10-Q of Unocal Corporation; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have: (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (c) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: November 14, 2003 /s/CHARLES R. WILLIAMSON --------------------------- Charles R. Williamson Chairman of the Board and Chief Executive Officer CERTIFICATIONS I, Terry G. Dallas, certify that: 1. I have reviewed this quarterly report on Form 10-Q of Unocal Corporation; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have: (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (c) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: November 14, 2003 /s/TERRY G. DALLAS --------------------------- Terry G. Dallas Executive Vice President and Chief Financial Officer -2- EX-32 7 q32003_ex32.txt 906 CERTIFICATIONS Exhibit 32 CERTIFICATION OF CHIEF EXECUTIVE OFFICER I, Charles R. Williamson, Chairman of the Board and Chief Executive Officer of Unocal Corporation (the "Company"), certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, that, to my knowledge: (1) the Quarterly Report on Form 10-Q of the Company for the quarterly period ended September 30, 2003 (the "Report"), fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and (2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. Dated: November 14, 2003 /s/ CHARLES R. WILLIAMOSN -------------------------- Charles R. Williamson CERTIFICATION OF CHIEF FINANCIAL OFFICER I, Terry G. Dallas, Executive Vice President and Chief Financial Officer of Unocal Corporation (the "Company"), certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, that to my knowledge: (1) the Quarterly Report on Form 10-Q of the Company for the quarterly period ended September 30, 2003 (the "Report"), fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and (2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. Dated: November 14, 2003 /s/TERRY G. DALLAS -------------------- Terry G. Dallas -2- -----END PRIVACY-ENHANCED MESSAGE-----