-----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, PCbN/OyXTZmdCji9lT87lQl+ItL/WD/carbeA2J6tG2d+F/vMgx+4lsY5UdIXtQM +kiJgBFtAsSiamjwtkVTIQ== 0000716039-03-000028.txt : 20030513 0000716039-03-000028.hdr.sgml : 20030513 20030512191952 ACCESSION NUMBER: 0000716039-03-000028 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 6 CONFORMED PERIOD OF REPORT: 20030331 FILED AS OF DATE: 20030513 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: 03693753 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 q12003_10q.txt 1ST 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 March 31, 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 April 30, 2003: 258,024,448 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....................... 27 Operating Highlights ............................................... 28 Item 3. Quantative and Qualitative Disclosures About Market Risk............ 38 Item 4. Controls and Procedures............................................. 42 PART II OTHER INFORMATION Item 1. Legal Proceedings................................................... 43 Item 6. Exhibits and Reports on Form 8-K.................................... 44 SIGNATURE................................................................... 45 CERTIFICATIONS.............................................................. 46 EXHIBIT INDEX............................................................... 48 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 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 measure of the amount of heat required to raise the temperature of one pound of water one degree Fahrenheit. 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 Ended March 31, -------------------------- Millions of dollars except per share amounts 2003 2002 - ---------------------------------------------------------------------------- Revenues Sales and operating revenues $ 1,775 $ 1,035 Interest, dividends and miscellaneous income 11 12 Gain on sales of assets 3 2 - ---------------------------------------------------------------------------- Total revenues 1,789 1,049 Costs and other deductions Crude oil, natural gas and product purchases 646 295 Operating expense 294 299 Administrative and general expense 51 43 Depreciation, depletion and amortization 260 224 Asset impairments - - Dry hole costs 71 28 Exploration expense 55 59 Interest expense 38 51 Property and other operating taxes 22 16 Distributions on convertible preferred securities of subsidiary trust 8 8 - ---------------------------------------------------------------------------- Total costs and other deductions 1,445 1,023 Earnings from equity investments 43 37 - ---------------------------------------------------------------------------- Earnings from continuing operations before income taxes and minority interests 387 63 - ---------------------------------------------------------------------------- Income taxes 168 40 Minority interests 2 1 - ---------------------------------------------------------------------------- Earnings from continuing operations 217 22 - ---------------------------------------------------------------------------- Earnings from discontinued operations - - Cumulative effects of accounting changes (a) (83) - - ---------------------------------------------------------------------------- Net earnings $ 134 $ 22 ============================================================================ Basic earnings per share of common stock (b) Continuing operations $ 0.84 $ 0.09 Net earnings $ 0.52 $ 0.09 Diluted earnings per share of common stock (c) Continuing operations $ 0.82 $ 0.09 Net earnings $ 0.52 $ 0.09 Cash dividends declared per share of common stock $ 0.20 $ 0.20 - ---------------------------------------------------------------------------- (a) Net of tax (benefit): $ ( 48) $ - (b) Basic weighted average shares outstanding (in thousands) 258,005 244,207 (c) Diluted weighted average shares outstanding (in thousands) 271,729 245,247 See Notes to the Consolidated Financial Statements.
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CONSOLIDATED BALANCE SHEET UNOCAL CORPORATION At March 31, At December 31, ------------------------------------------- Millions of dollars 2003 (a) 2002 - --------------------------------------------------------------------------------------------------------------------- Assets Current assets Cash and cash equivalents $ 356 $ 168 Accounts and notes receivable - net 1,116 994 Inventories 91 97 Deferred income taxes 120 90 Other current assets 27 26 - --------------------------------------------------------------------------------------------------------------------- Total current assets 1,710 1,375 Investments and long-term receivables - net 1,038 1,044 Properties - net (b) 8,114 7,879 Goodwill 125 122 Deferred income taxes 231 210 Other assets 150 130 - --------------------------------------------------------------------------------------------------------------------- Total assets $ 11,368 $ 10,760 ===================================================================================================================== Liabilities and Stockholders' Equity Current liabilities Accounts payable $ 1,110 $ 1,024 Taxes payable 346 223 Dividends payable 51 51 Interest payable 52 50 Current portion of environmental liabilities 131 113 Current portion of long-term debt and capital leases 6 6 Other current liabilities 173 165 - --------------------------------------------------------------------------------------------------------------------- Total current liabilities 1,869 1,632 Long-term debt and capital leases 2,918 3,002 Deferred income taxes 631 593 Accrued abandonment, restoration and environmental liabilities 878 622 Other deferred credits and liabilities 846 816 Minority interests 275 275 Commitments and contingencies - Note 13 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 963 962 Unearned portion of restricted stock issued (17) (20) Retained earnings 3,103 3,021 Accumulated other comprehensive income (443) (486) Notes receivable - key employees (35) (37) Treasury stock - at cost (d) (411) (411) - --------------------------------------------------------------------------------------------------------------------- Total stockholders' equity 3,429 3,298 - --------------------------------------------------------------------------------------------------------------------- Total liabilities and stockholders' equity $ 11,368 $ 10,760 ===================================================================================================================== (a) Unaudited (b) Net of accumulated depreciation, depletion and amortization of: $ 12,538 $ 12,277 (c) Number of shares outstanding (in thousands) 258,005 257,980 (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 Three Months Ended March 31, --------------------------------- Millions of dollars 2003 2002 - --------------------------------------------------------------------------------------------------------------------------- Cash Flows from Operating Activities Net earnings $ 134 $ 22 Adjustments to reconcile net earnings to net cash provided by operating activities Depreciation, depletion and amortization 260 224 Asset impairments - - Dry hole costs 71 28 Amortization of exploratory leasehold costs 24 22 Deferred income taxes 30 (23) Gain on sales of assets (pre-tax) (3) (2) Cumulative effects of accounting changes 83 - Other 32 (11) Working capital and other changes related to operations Accounts and notes receivable (122) (14) Inventories 6 6 Accounts payable 86 (51) Taxes payable 123 82 Other (39) (12) - --------------------------------------------------------------------------------------------------------------------------- Net cash provided by operating activities 685 271 - --------------------------------------------------------------------------------------------------------------------------- Cash Flows from Investing Activities Capital expenditures (includes dry hole costs) (429) (390) Proceeds from sales of assets 66 28 Proceeds from sale of discontinued operations - 2 - --------------------------------------------------------------------------------------------------------------------------- Net cash used in investing activities (363) (360) - --------------------------------------------------------------------------------------------------------------------------- Cash Flows from Financing Activities Long-term borrowings 16 399 Reduction of long-term debt and capital lease obligations (100) (123) Minority interests (2) (2) Proceeds from issuance of common stock 1 14 Dividends paid on common stock (52) (49) Other 3 (2) - --------------------------------------------------------------------------------------------------------------------------- Net cash provided by (used in) financing activities (134) 237 - --------------------------------------------------------------------------------------------------------------------------- Net increase in cash and cash equivalents 188 148 - --------------------------------------------------------------------------------------------------------------------------- Cash and cash equivalents at beginning of year 168 190 - --------------------------------------------------------------------------------------------------------------------------- Cash and cash equivalents at end of period $ 356 $ 338 =========================================================================================================================== Supplemental disclosure of cash flow information: Cash paid during the period for: Interest (net of amount capitalized) $ 35 $ 53 Income taxes (net of refunds) $ 23 $ (8) 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 three months ended March 31, 2003, are not necessarily indicative of future financial results. Certain items in the prior year financial statements 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. The Company previously used the units-of-production method to accrue these costs. 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 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. At January 1, 2003 and March 31, 2003, the Company had accrued a total of $758 million and $762 million, respectively, in estimated abandonment and restoration costs. First quarter 2003 accretion expense of approximately $11 million pre-tax was partially offset by abandonment liability settlements completed during the period. There were no material abandonment and restoration liabilities incurred or revisions in abandonment and restoration cost estimates during the first quarter 2003. The March 31, 2003 liability amount represents approximately one-half of the Company's determinable abandonment and restoration costs, adjusted for inflation. The Company estimates that the impact of adopting SFAS No. 143 on its 2003 operating earnings will be an incremental charge of approximately $9 million after tax. Had the Company been required to adopt SFAS No. 143 on January 1, 2002, the estimated liability for abandonment and restoration costs using current assumptions would have been approximately $713 million and $723 million at January 1, 2002 and March 31, 2002 respectively. Pro-forma net income information for the period ended March 31, 2002 is as follows: As Pro- Millions of dollars except per share amounts Reported Forma - -------------------------------------------- ------------ ------------- Net Income $22 $20 Earnings per Share: Basic $0.09 $0.08 Diluted $0.09 $0.08 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 7 for further details). This change is estimated to decrease 2003 after-tax income by approximately $5 million. When fully phased in for future grants over the next three years, the annual expense is estimated to be approximately $10 million after-tax. Adoption of the fair value recognition provisions will not have a material effect on the Company's 2003 financial position or results of operations. 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 13. 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 companies that are defined as variable interest entities. This Interpretation is effective for new variable interest entities as of February 1, 2003. The effective date for the consolidation of entities existing prior to February 1, 2003 is July 1, 2003. The Company has included the disclosure requirements of the Interpretation in this report and expects the adoption of the recognition (i.e., consolidation) requirements of the Interpretation to increase its consolidated long-term debt by approximately $320 million in the third quarter of 2003. This amount will include $242 million related to a partnership interest in which the Company currently has a minority interest liability (see note 11 for further details) and $78 million of third-party debt related to Dayabumi Salak Pratma, Ltd. ("DSPL"), an equity investee that sells electricity generated from geothermal steam in Indonesia (see note 11 for further details). 3. Other Financial Information During the first quarters of 2003 and 2002, approximately 25 percent and 20 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. 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 $16 million and $9 million for the first quarters of 2003 and 2002, respectively. Exploration expense on the consolidated earnings statement consisted of the following:
For the Three Months Ended March 31, --------------------------- Millions of dollars 2003 2002 - -------------------------------------------------------------------------------- Exploration operations $ 15 $ 23 Geological and geophysical 14 11 Amortization of exploratory leases 24 22 Leasehold rentals 2 3 - -------------------------------------------------------------------------------- Exploration expense $ 55 $ 59 ================================================================================
-6- 4. Restructuring In 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 March 31, 2003, approximately $14 million of the restructuring costs had been paid and charged against the liability, leaving accrued costs of $5 million on the consolidated balance sheet at March 31, 2003. The remaining costs are expected to be paid by the end of 2003. Also in 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 38 had been terminated, as of March 31, 2003. Approximately $1 million of the restructuring costs had been paid and charged against the liability, leaving accrued costs of $3 million on the consolidated balance sheet at March 31, 2003. The remaining costs are expected to be paid during 2003 and the first half of 2004. 5. Income Taxes Income taxes on earnings from continuing operations for the first quarter of 2003 were $168 million compared with $40 million first quarter of 2002. The effective income tax rate for the first quarter of 2003 was 43 percent compared with 63 percent for the first quarter of 2002. The lower effective tax rate in 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. Foreign earnings are generally taxed at higher rates. 6. 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 three months ended March 31, 2003 and 2002:
Earnings Shares Per Share Millions except per share amounts (Numerator) (Denominator) Amount - ---------------------------------------------------------------------------------------------------------------------------- Three months ended March 31, 2003 Earnings from continuing operations $ 217 258.0 Basic EPS $ 0.84 ============ Effect of dilutive securities Options and common stock equivalents 1.5 -------------------------------- 217 259.5 $ 0.84 Distributions on subsidiary trust preferred securities (after-tax) 7 12.3 -------------------------------- Diluted EPS $ 224 271.8 $ 0.82 ============ Three months ended March 31, 2002 Earnings from continuing operations $ 22 244.2 Basic EPS $ 0.09 ============ Effect of dilutive securities Options and common stock equivalents 1.0 -------------------------------- Diluted EPS 22 245.2 $ 0.09 ============ Distributions on subsidiary trust preferred securities (after-tax) 7 12.3 -------------------------------- Antidilutive $ 29 257.5 $ 0.11 - ----------------------------------------------------------------------------------------------------------------------------
Not included in the computation of diluted EPS for the three months ended March 31, 2003 and 2002, were options outstanding to purchase approximately 11 million and 5.1 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. -7- 7. 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 Ended March 31, ------------------------ Millions of dollars except per share amounts 2003 2002 - -------------------------------------------------------------------------------- Net earnings As reported $ 134 $ 22 Add: Stock-based employee compensation expense included in reported net income, net of related tax effects and minority interests 2 7 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 (4) (12) ------------------------ Pro forma net earnings $ 132 $ 17 ======================== Net earnings per share: Basic - as reported $ 0.52 $ 0.09 Basic - pro forma $ 0.51 $ 0.07 Diluted - as reported $ 0.52 $ 0.09 Diluted - pro forma $ 0.51 $ 0.07
8. Comprehensive Income The Company's comprehensive income was:
For the Three Months Ended March 31, ----------------------- Millions of dollars 2003 2002 - -------------------------------------------------------------------------------- Net earnings $ 134 $ 22 Change in unrealized loss on hedging instruments (a) (10) (20) Reclassification adjustment for settled hedging contracts (b) 7 6 Unrealized foreign currency translation adjustments 46 (3) - -------------------------------------------------------------------------------- Total comprehensive income $ 177 $ 5 ================================================================================ (a) Net of tax effect of: (6) (12) (b) Net of tax effect of: 4 3
-8- 9. Cash and Cash Equivalents
At March 31, At December 31, ---------------------------------------- Millions of dollars 2003 2002 - -------------------------------------------------------------------------------- Cash $ 157 $ 58 Time deposits 131 110 Restricted cash 1 - Marketable securities 67 - - -------------------------------------------------------------------------------- Cash and cash equivalents $ 356 $ 168 ================================================================================
The marketable securities at March 31, 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. 10. Long Term Debt and Credit Agreements During the first three months of 2003, the Company's consolidated debt, including the current portion, decreased by $84 million. The Company retired $89 million in 9.25% debentures which matured during the first quarter and paid down $10 million of medium-term notes which matured during the quarter. These decreases were partially offset by a $15 million increase in the Company's 3-year $295 million Canadian dollar-denominated non-revolving credit facility. At March 31, 2003, the borrowings under the credit facility translated to $201 million, using applicable foreign exchange rates. 11. Variable Interest Entities 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 Energy 76 Development, L.P. ("Spirit LP"), a limited partnership. 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. The Company consolidates this partnership. The fixed-price overrides are subject to economic limitations of production from the affected fields. The limited partner is entitled to receive a priority allocation of profits and cash distributions. The limited partner's share has a maximum term of 20 years, but may terminate in 2005 under certain conditions. If the Company's credit rating falls below Ba1 or BB+, then the priority return to the limited partner increases by two percent and the Company would have to provide cash collateral or a letter of credit for the $250 million. Almost all the minority interests in earnings are paid out to the limited partner as cash distributions. The minority interest on the Company's consolidated balance sheet related to this transaction was approximately $252 million at March 31, 2003. The primary purpose of this transaction was to raise capital. In the third quarter of 2003, FASB Interpretation No. 46 will require that the Company consolidate the unaffiliated investor (see note 2). This is expected to result in a reclassification of $242 million from minority interests to long-term debt on the Company's consolidated balance sheet. At March 31, 2003, the Company's maximum exposure to loss as a result of its involvement with Spirit Energy 76 Development, L.P. was approximately $251 million. DSPL is a special purpose company formed for the purpose of building and operating a geothermal energy fueled power generating facility in Indonesia. Under a long-term electricity sales contract, this entity 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 $85 million at March 31, 2003. DSPL's debt obligations are non-recourse to UGI and to the Company, as neither entity has guaranteed these obligations. Effective in the third quarter of 2003, FASB Interpretation No. 46 (see note 2 for further details), will require the Company to consolidate DSPL, resulting in the reporting of the $78 million as long-term debt on the consolidated balance sheet at that time. At March 31, 2003, the Company's maximum exposure to loss as a result of its involvement with DSPL was approximately $100 million. -9- 12. 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). At March 31, 2003, the Company had accrued $762 million in estimated abandonment and restoration costs as liabilities. This amount represented approximately one-half of the Company's determinable abandonment and restoration costs, adjusted for inflation. Accretion expense for the first quarter was approximately $11 million pre-tax (see note 2). There were no material abandonment and restoration liabilities incurred or settled during the first quarter. The Company's reserve for environmental remediation obligations at March 31, 2003 totaled $249 million, of which $131 million was included in current liabilities. This compared with $245 million at December 31, 2002, of which $113 million was included in current liabilities. 13. 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 12, at March 31, 2003, the Company had accrued $249 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 $215 million. The amount of such possible additional costs reflects the aggregate of the high ends of the ranges of costs of feasible alternatives -10- 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. The accrued costs and the possible additional costs are shown below for four categories of sites:
At March 31, 2003 ---------------------------- Possible Additional Millions of dollars Reserve Costs - -------------------------------------------------------------------------------- Superfund and similar sites $ 17 $ 10 Active Company facilities 34 25 Company facilities sold with retained liabilities and former Company-operated sites 102 80 Inactive or closed Company facilities 96 100 - -------------------------------------------------------------------------------- Total $ 249 $ 215 ================================================================================
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 -11- 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. 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 March 31, 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, two 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. Of the remaining 19 sites, where the Company has concluded that liability is probable and to the extent costs can be reasonably estimated, a reserve of $13 million has been established for future remediation and settlement costs. Various state agencies and private parties had identified 18 other similar PRP sites. Two 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 two 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 13 sites, a reserve of $4 million has been established for future remediation and settlement costs. The sites discussed above exclude 121 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 $34 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 made payments of $4 million for this category of sites in the first quarter 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. -12- 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 $102 million for this group of sites. Payments of $4 million were made during the first three 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 $96 million has been established for these types of facilities. In the first quarter of 2003, provisions of $11 million were recorded for the "Inactive or closed Company facilities" category of sites, primarily for remediation projects at the Company's former refinery in Beaumont, Texas. 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 quarter, 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 in the first quarter. In the first quarter of 2003, $3 million in payments were made 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. 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 March 31, 2003, amounts in the remediation reserve for these facilities totaled $101 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 $70 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 -13- 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. 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, and that releases from sites owned by Unocal subsequently impacted the wellfield. 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. Further proceedings on this cross-complaint remain stayed. In November 2002, the City, ChevronTexaco and ExxonMobil entered into a settlement (the "Chevron-Exxon Settlement"), subject to court approval, under which the two companies would pay the City $30 million and construct and operate a water treatment plant. The City's expert has estimated that the cost of treatment plant construction and operation could exceed $500 million, but other experts estimate the cost of aquifer restoration at $33 million. The Company, Tosco Corporation (now part of Conoco Phillips) and other defendants, but not the Shell defendants, had been invited to participate in this settlement on terms which would have involved the Company paying the City $7.5 million and contributing to the costs of the treatment plant. Neither the Company nor the other invited defendants elected to participate on these terms and in March 2003, the Company, BP (named in the suit as "ARCO") and Ultramar filed a joint opposition to the Chevron-Exxon Settlement. The court held a hearing on March 24, 2003 to consider approval of the settlement and its value as a credit against future recoveries from non-settling parties, which the settling parties have proposed at $40 million. The court took the matter under submission but expressed concern that the provision allowing ChevronTexaco and ExxonMobil to "veto" a settlement by other parties was improper. ARCO has announced that it settled with the City for $9,750,000 and has withdrawn its objections to the Chevron-Exxon settlement. Unocal and Ultramar were offered settlements at the same amount as ARCO. Unocal has rejected that offer but is seeking good faith negotiations with the City. The City has agreed, but no date for such negotiations has been set. Based on a rigorous technical analysis of the data, the Company believes it has strong defenses to the allegations in the complaint, including the lack of evidence that its former service stations or activities are responsible for any contamination that has reached or threatens the wellfield. The Company also believes it has certain available defenses that the settling defendants and others may not have due to tolling agreements they entered into with the City; and, unlike the Shell defendants and the settling defendants, the Company is neither the object of punitive damages claims nor a cause of the wellfield's being originally shut down. The Company is also subject to potential partial responsibility for MTBE or TBA contamination in the wellfield arising from certain operations in the area of the Company's former gasoline marketing business that was sold in 1997, and is subject to potential liability, under a products liability theory, for gasoline it manufactured or sold that was ultimately distributed to area facilities operated by others. The Company's current analysis does not indicate any such liabilities are likely to be significant. -14- 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 is reached by March 31, 2003. The EPA also intends to defer to the City of Santa Monica's request to select and implement a wellhead treatment system. The Company received a copy of this letter. 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. 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"). 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. 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. -15- The Company believes that certain portions of its disputes with Agrium are subject to binding arbitration under the terms of the GPSA. The Company initiated the Arbitration to determine the amount and delivery rate of the remaining gas supply available under that agreement. Agrium claims the dispute resolution provisions of the PSA supersede the arbitration provisions of the GPSA. In January 2003, the state court ordered that the arbitration issues should be combined in the litigation but the scope of the court's order is unclear. Agrium has filed a motion to clarify the order with respect to the Arbitration. The Company is appealing the order and has filed a motion to stay discovery pending resolution of that appeal. The parties have agreed in principle to postpone the Arbitration, pending resolution of the appeal. Discovery is now proceeding. Petrobangla Claim: 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, 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) 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. 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 and expects to commence litigation in the event that the 2002 payment is not received. The potential cash exposure to the Company is $27 million. 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. -16- 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 under examination by the Internal Revenue Service. 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 March 31, 2003, the reserve for this category totaled $102 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 $21 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. -17- 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 March 31, 2003, the Company had obtained various surety bonds for approximately $220 million. These surety bonds included a bond for $90 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 $130 million in various other routine performance bonds held by local, city, state and federal agencies. The Company also had obtained approximately $33 million in standby letters of credit at March 31, 2003. The Company has entered into indemnification obligations in favor of the providers of these surety bonds and letters of credit. In addition, the Company has various other guarantees for approximately $550 million. Guarantees for approximately $333 million of this amount 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 $250 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. Approximately $134 million of the $550 million in guarantees mentioned in the previous paragraph represents 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. Other matters The Company has a lease agreement relating to its Discoverer Spirit deepwater drillship, with a remaining term of approximately two and a half years at March 31, 2003. The drillship has a current minimum daily rate of approximately $224,000. The future remaining minimum lease payment obligation was approximately $200 million at March 31, 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. -18- 14. 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 March 31, 2003, including the current portion, was approximately $3,296 million. 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 $506 million at March 31, 2003. The fair value was based on the closing trading price of the preferred securities on March 31, 2003. Commodity hedging activities - The Company uses hydrocarbon derivatives to mitigate its overall exposure to fluctuations in hydrocarbon commodity prices. During the three months ended March 31, 2003, the amount of the ineffectiveness for both cash flow and fair value hedges was immaterial. At March 31, 2003, the Company had approximately $25 million of after-tax deferred losses in accumulated other comprehensive income on the consolidated balance sheet related to cash flow hedges for future commodity sales for the period beginning April 2003 through October 2004. Of this amount, approximately $20 million in after-tax losses are expected to be reclassified to the consolidated earnings statement during the next twelve months. Foreign currency contracts - At March 31, 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. All of this 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 March 31, 2003, the Company had approximately $24 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. -19- 15. 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 March 31, 2003 Unocal Non- Unocal Capital Union Oil Guarantor Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated - ----------------------------------------------------------------------------------------------------------------------------- Revenues Sales and operating revenues $ - $ - $ 512 $ 1,690 $ (427) $ 1,775 Interest, dividends and miscellaneous income - 8 11 2 (10) 11 Gain on sales of assets - - (9) 12 - 3 - ----------------------------------------------------------------------------------------------------------------------------- Total revenues - 8 514 1,704 (437) 1,789 Costs and other deductions Purchases, operating and other expenses 2 - 282 1,211 (427) 1,068 Depreciation, depletion and amortization - - 106 154 - 260 Dry hole costs - - 52 19 - 71 Interest expense 8 - 30 10 (10) 38 Distributions on convertible preferred securities - 8 - - - 8 - ----------------------------------------------------------------------------------------------------------------------------- Total costs and other deductions 10 8 470 1,394 (437) 1,445 Equity in earnings of subsidiaries 142 - 211 - (353) - Earnings from equity investments - - 3 40 - 43 - ----------------------------------------------------------------------------------------------------------------------------- Earnings from continuing operations before income taxes and minority interests 132 - 258 350 (353) 387 - ----------------------------------------------------------------------------------------------------------------------------- Income taxes (2) - 31 139 - 168 Minority interests - - - 2 - 2 - ----------------------------------------------------------------------------------------------------------------------------- Earnings from continuing operations 134 - 227 209 (353) 217 Earnings from discontinued operations - - - - - - Cumulative effects of accounting changes - - (85) 2 - (83) - ----------------------------------------------------------------------------------------------------------------------------- Net earnings $ 134 $ - $ 142 $ 211 $ (353) $ 134 =============================================================================================================================
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CONDENSED CONSOLIDATED EARNINGS STATEMENT Three months ended March 31, 2002 Unocal Non- Unocal Capital Union Oil Guarantor Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated - ----------------------------------------------------------------------------------------------------------------------------- Revenues Sales and operating revenues $ - $ - $ 209 $ 992 $ (166) $ 1,035 Interest, dividends and miscellaneous income - 8 7 5 (8) 12 Gain (loss) on sales of assets - - 13 (11) - 2 - ----------------------------------------------------------------------------------------------------------------------------- Total revenues - 8 229 986 (174) 1,049 Costs and other deductions Purchases, operating and other expenses 2 - 227 645 (162) 712 Depreciation, depletion and amortization - - 87 137 - 224 Dry hole costs - - 15 13 - 28 Interest expense 8 - 43 9 (9) 51 Distributions on convertible preferred securities - 8 - - - 8 - ----------------------------------------------------------------------------------------------------------------------------- Total costs and other deductions 10 8 372 804 (171) 1,023 Equity in earnings of subsidiaries 32 - 128 - (160) - Earnings from equity investments - - - 37 - 37 - ----------------------------------------------------------------------------------------------------------------------------- Earnings from continuing operations before income taxes and minority interests 22 - (15) 219 (163) 63 - ----------------------------------------------------------------------------------------------------------------------------- Income taxes (2) - (47) 89 - 40 Minority interests - - - 2 (1) 1 - ----------------------------------------------------------------------------------------------------------------------------- Earnings from continuing operations 24 - 32 128 (162) 22 Earnings from discontinued operations - - - - - - Cumulative effects of accounting changes - - - - - - - ----------------------------------------------------------------------------------------------------------------------------- Net earnings $ 24 $ - $ 32 $ 128 $ (162) $ 22 =============================================================================================================================
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CONDENSED CONSOLIDATED BALANCE SHEET At March 31, 2003 Unocal Non- Unocal Capital Union Oil Guarantor Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated - ----------------------------------------------------------------------------------------------------------------------------- Assets Current assets Cash and cash equivalents $ - $ - $ 53 $ 303 $ - $ 356 Accounts and notes receivable - net 53 - 263 880 (80) 1,116 Inventories - - 12 79 - 91 Other current assets 1 - 110 36 - 147 - ----------------------------------------------------------------------------------------------------------------------------- Total current assets 54 - 438 1,298 (80) 1,710 Investments and long-term receivables - net 4,694 - 4,709 949 (9,314) 1,038 Properties - net - - 2,229 5,885 - 8,114 Other assets including goodwill 3 541 234 514 (786) 506 - ----------------------------------------------------------------------------------------------------------------------------- Total assets $4,751 $ 541 $ 7,610 $ 8,646 $ (10,180) $ 11,368 ============================================================================================================================= Liabilities and Stockholders' Equity Current liabilities Accounts payable $ - $ - $ 298 $ 865 $ (53) $ 1,110 Current portion of long-term debt and capital leases - - - 6 - 6 Other current liabilities 51 3 341 387 (29) 753 - ----------------------------------------------------------------------------------------------------------------------------- Total current liabilities 51 3 639 1,258 (82) 1,869 Long-term debt and capital leases - - 2,321 597 - 2,918 Deferred income taxes - - (145) 776 - 631 Accrued abandonment, restoration and environmental liabilities - - 437 441 - 878 Other deferred credits and liabilities 541 - 445 636 (776) 846 Minority interests - - - 315 (40) 275 Company-obligated mandatorily redeemable convertible preferred securities of a subsidiary trust holding solely parent debentures - 522 - - - 522 Stockholders' equity 4,159 16 3,913 4,623 (9,282) 3,429 - ----------------------------------------------------------------------------------------------------------------------------- Total liabilities and stockholders' equity $4,751 $ 541 $ 7,610 $ 8,646 $ (10,180) $ 11,368 =============================================================================================================================
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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 =============================================================================================================================
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CONDENSED CONSOLIDATED CASH FLOWS For the Three Months Ended March 31, 2003 Unocal Non- Unocal Capital Union Oil Guarantor Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated - ----------------------------------------------------------------------------------------------------------------------------- Cash Flows from Operating Activities $ 51 $ - $ 221 $ 413 $ - $ 685 Cash Flows from Investing Activities Capital expenditures and acquisitions (includes dry hole costs) - - ( 95) (334) - (429) Proceeds from sales of assets and discontinued operations - - 42 24 - 66 - ----------------------------------------------------------------------------------------------------------------------------- Net cash used in investing activities - - (53) (310) - (363) - ----------------------------------------------------------------------------------------------------------------------------- Cash Flows from Financing Activities Change in long-term debt and capital leases - - (97) 13 - (84) Dividends paid on common stock (52) - - - - (52) Minority interests - - - (2) - (2) Other 1 - - 3 - 4 - ----------------------------------------------------------------------------------------------------------------------------- Net cash provided by (used in) financing activities (51) - (97) 14 - (134) - ----------------------------------------------------------------------------------------------------------------------------- Increase in cash and cash equivalents - - 71 117 - 188 - ----------------------------------------------------------------------------------------------------------------------------- Cash and cash equivalents at beginning of period - - (18) 186 - 168 - ----------------------------------------------------------------------------------------------------------------------------- Cash and cash equivalents at end of period $ - $ - $ 53 $ 303 $ - $ 356 =============================================================================================================================
CONDENSED CONSOLIDATED CASH FLOWS For the Three Months Ended March 31, 2002 Unocal Non- Unocal Capital Union Oil Guarantor Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated - ----------------------------------------------------------------------------------------------------------------------------- Cash Flows from Operating Activities $ 36 $ - $ ( 192) $ 427 $ - $ 271 Cash Flows from Investing Activities Capital expenditures and acquisitions (includes dry hole costs) - - ( 98) (292) - (390) Proceeds from sales of assets and discontinued operations - - 3 27 - 30 - ----------------------------------------------------------------------------------------------------------------------------- Net cash used in investing activities - - (95) (265) - (360) - ----------------------------------------------------------------------------------------------------------------------------- Cash Flows from Financing Activities Change in long-term debt and capital leases - - 376 (100) - 276 Dividends paid on common stock (49) - - - - (49) Minority interests - - - (2) - (2) Other 14 - (2) - - 12 - ----------------------------------------------------------------------------------------------------------------------------- Net cash provided by (used in) financing activities (35) - 374) (102) - 237 - ----------------------------------------------------------------------------------------------------------------------------- Increase in cash and cash equivalents 1 - 87 60 - 148 - ----------------------------------------------------------------------------------------------------------------------------- Cash and cash equivalents at beginning of period - - 62 128 - 190 - ----------------------------------------------------------------------------------------------------------------------------- Cash and cash equivalents at end of period $ 1 $ - $ 149 $ 188 $ - $ 338 =============================================================================================================================
-24- 16. 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 March 31, 2003 Millions of dollars U.S. Lower 48 Alaska Canada Far East Other - --------------------------------------------------------------------------------------------------------------------------- Sales & operating revenues $ 161 $ 66 $ 58 $ 309 $ 53 $ 920 Other income (loss) (a) 3 - - - - (1) Inter-segment revenues 388 - 38 91 - - - --------------------------------------------------------------------------------------------------------------------------- Total 552 66 96 400 53 919 Earnings from equity investments 3 - - 9 4 1 Earnings (loss) from continuing operations 111 15 24 121 21 (9) Earnings from discontinued operations - - - - - - Cumulative effects of accounting changes (b) 11 (43) 4 13 - - - --------------------------------------------------------------------------------------------------------------------------- Net earnings (loss) 122 (28) 28 134 21 (9) - --------------------------------------------------------------------------------------------------------------------------- Assets (at March 31, 2003) 3,333 336 1,243 2,934 868 385 - ---------------------------------------------------------------------------------------------------------------------------
Midstream Geothermal Corporate & Other Total & Power Operations Admin Net Interest Environmental & General Expense & Litigation Other (c) - --------------------------------------------------------------------------------------------------------------------------- Sales & operating revenues $ 141 $ 35 $ - $ - $ - $ 32 $ 1,775 Other income (loss) (a) 1 - - 4 - 7 14 Inter-segment revenues 2 - - - - (519) - - --------------------------------------------------------------------------------------------------------------------------- Total 144 35 - 4 - (480) 1,789 Earnings from equity investments 15 1 - - - 10 43 Earnings (loss) from continuing operations 18 12 (23) (31) (17) (25) 217 Earnings from discontinued operations - - - - - - - Cumulative effects of accounting changes (b) (2) - - - - (66) (83) - --------------------------------------------------------------------------------------------------------------------------- Net earnings (loss) 16 12 (23) (31) (17) (91) 134 - --------------------------------------------------------------------------------------------------------------------------- Assets (at March 31, 2003) 538 530 - - - 1,201 11,368 - --------------------------------------------------------------------------------------------------------------------------- (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.
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Segment Information Exploration & Production Trade For the Three Months North America International ended March 31, 2002 Millions of dollars U.S. Lower 48 Alaska Canada Far East Other - --------------------------------------------------------------------------------------------------------------------------- Sales & operating revenues $ 114 $ 51 $ 40 $ 230 $ 23 $ 456 Other income (a) 3 - - - - - Inter-segment revenues 166 - - 52 20 - - --------------------------------------------------------------------------------------------------------------------------- Total 283 51 40 282 43 456 Earnings (loss) from equity investments (1) - - 8 2 (1) Earnings (loss) from continuing operations 4 (6) (9) 90 12 1 Earnings from discontinued operations - - - - - - Cumulative effects of accounting changes - - - - - - - -------------------------------------------------------------------------------------------------------------------------- Net earnings (loss) 4 (6) (9) 90 12 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 $ 62 $ 28 $ - $ - $ - $ 31 $ 1,035 Other income (a) 1 2 - 3 - 5 14 Inter-segment revenues 2 - - - - (240) - - --------------------------------------------------------------------------------------------------------------------------- Total 65 30 - 3 - (204) 1,049 Earnings (loss) from equity investments 19 (3) - - - 13 37 Earnings (loss) from continuing operations 19 6 (24) (37) (23) (11) 22 Earnings from discontinued operations - - - - - - - Cumulative effects of accounting changes - - - - - - - - --------------------------------------------------------------------------------------------------------------------------- Net earnings (loss) 19 6 (24) (37) (23) (11) 22 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.
-26- 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 Ended March 31, -------------------------- Millions of dollars 2003 2002 - -------------------------------------------------------------------------------- Earnings from continuing operations $ 217 $ 22 Earnings from discontinued operations - - Cumulative effects of accounting changes (83) - - -------------------------------------------------------------------------------- Net earnings $ 134 $ 22 ================================================================================
Continuing Operations First Quarter Results: Earnings from continuing operations increased by $195 million in the first quarter of 2003 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 $230 million. The Company's worldwide average realized natural gas price, including a loss of 27 cents per Mcf from hedging activities, was $3.90 per Mcf for the first quarter of 2003. This was an increase of $1.44 per Mcf, or 59 percent, from the $2.46 per Mcf, including a benefit of 9 cents per Mcf from hedging activities, realized during the first quarter of 2002. In the first quarter of 2003, the Company's worldwide average realized liquids price was $29.99 per Bbl, which was an increase of $11.13 per Bbl, or 59 percent, from the same period a year ago. The Company's hedging program lowered the average realized liquids price by 50 cents per Bbl in the first quarter of 2003 while the first quarter of 2002 included a gain of 6 cents per Bbl from hedging activities. The first quarter of 2003 included an after-tax gain of $2 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, compared to an after-tax loss of $4 million in the same period a year ago. After-tax environmental and litigation expenses were $17 million in the first quarter of 2003, compared with $26 million in the same period a year ago. These positive variance factors were partially offset by higher dry hole costs, higher DD&A rates (including asset retirement obligation accretion), higher pension related expenses and lower North America liquids production, which reduced net earnings by approximately $25 million, $20 million, $10 million and $10 million, respectively, in the first quarter of 2003 compared with the same period a year ago. North America liquids production averaged 88,000 Bbl/d in the first quarter of 2003, down from 99,000 Bbl/d 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. 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. -27- Revenues Revenues from continuing operations for the first quarter of 2003 were $1.79 billion compared with $1.05 billion for the same period a year ago. The increase primarily reflected higher natural gas and liquids prices.
OPERATING HIGHLIGHTS UNOCAL CORPORATION For the Three Months Ended March 31, --------------------------- 2003 2002 - ---------------------------------------------------------------------------- North America Net Daily Production Liquids (thousand barrels) U.S. Lower 48 (a) (b) 48 56 Alaska 22 25 Canada 18 18 - ---------------------------------------------------------------------------- Total liquids 88 99 Natural gas - dry basis (million cubic feet) U.S. Lower 48 (a) (b) 700 746 Alaska 61 101 Canada 97 90 - ---------------------------------------------------------------------------- Total natural gas 858 937 North America Average Prices (excluding hedging activities) (c) (d) Liquids (per barrel) U.S. Lower 48 $30.53 $18.36 Alaska $33.48 $18.61 Canada $28.44 $16.52 Average $30.77 $18.06 Natural gas (per mcf) U.S. Lower 48 $ 6.29 $ 2.23 Alaska $ 1.20 $ 1.57 Canada $ 5.64 $ 2.34 Average $ 5.83 $ 2.16 - ---------------------------------------------------------------------------- North America Average Prices (including hedging activities) (c) (d) Liquids (per barrel) U.S. Lower 48 $28.97 $18.54 Alaska $33.48 $18.61 Canada $28.44 $16.52 Average $29.90 $18.17 Natural gas (per mcf) U.S. Lower 48 $ 5.61 $ 2.47 Alaska $ 1.20 $ 1.57 Canada $ 5.33 $ 2.25 Average $ 5.25 $ 2.35 - ---------------------------------------------------------------------------- (a) Includes proportional interests in production of equity investees. (b) Includes minority interests of : Liquids 1 9 Natural gas 10 98 Barrels oil equivalent 2 25 (c) Excludes Trade segment margins. (d) Excludes gains/losses on derivative positions not accounted for as hedges and ineffective portions of hedges.
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OPERATING HIGHLIGHTS (CONTINUED) UNOCAL CORPORATION For the Three Months Ended March 31, --------------------------- 2003 2002 - ---------------------------------------------------------------------------- International Net Daily Production (e) Liquids (thousand barrels) Far East 55 53 Other (a) 21 20 - ---------------------------------------------------------------------------- Total liquids 76 73 Natural gas - dry basis (million cubic feet) Far East 875 822 Other (a) 107 75 - ---------------------------------------------------------------------------- Total natural gas 982 897 International Average Prices (f) Liquids (per barrel) Far East $29.69 $19.28 Other $32.21 $21.96 Average $30.11 $19.86 Natural gas (per mcf) Far East $ 2.76 $ 2.59 Other $ 2.83 $ 2.48 Average $ 2.77 $ 2.58 - ---------------------------------------------------------------------------- Worldwide Net Daily Production (a) (b) (e) Liquids (thousand barrels) 164 172 Natural gas - dry basis (million cubic feet) 1,840 1,834 Barrels oil equivalent (thousands) 471 477 Worldwide Average Prices (excluding hedging activities) (c) (d) Liquids (per barrel) $30.49 $18.80 Natural gas (per mcf) $ 4.17 $ 2.37 Worldwide Average Prices (including hedging activities) (c) (d)(f) Liquids (per barrel) $ 29.99 $18.86 Natural gas (per mcf) $ 3.90 $ 2.46 - ---------------------------------------------------------------------------- (a) Includes proportional interests in production of equity investees. (b) Includes minority interests of : Liquids 1 9 Natural gas 10 98 Barrels oil equivalent 2 25 (c) Excludes Trade segment margins. (d) Excludes gains/losses on derivative positions not accounted for as hedges and ineffective portions of hedges. (e) International production is presented utilizing the economic interest method. (f) International did not have any hedging activities.
-29- Exploration and Production The Company engages in oil and gas exploration, development and production worldwide. The results of this segment are discussed under the following two geographical breakdowns: 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, excluding production from the Company's Pure Resources, Inc. ("Pure") subsidiary, 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, 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. First Quarter Results: Earnings from continuing operations were $150 million in the first quarter of 2003 compared to a loss of $11 million for the same period a year ago, which was an increase of $161 million. The increase was primarily due to higher natural gas and liquids prices, which increased net earnings by approximately $130 million and $55 million, respectively. North America's average realized natural gas price, including a loss of 58 cents per Mcf from hedging activities, was $5.25 per Mcf for the first quarter of 2003. This was an increase of $2.90 per Mcf, or 123 percent, from the $2.35 per Mcf, including a benefit of 19 cents per Mcf from hedging activities, realized during the first quarter of 2002. In the first quarter of 2003, North America's worldwide average realized liquids price was $29.90 per Bbl, which was an increase of $11.73 per Bbl, or 65 percent, from the same period a year ago. The Company's hedging program lowered the average realized liquids price by 87 cents per Bbl in the first quarter of 2003 while the first quarter of 2002 included a gain of 11 cents per Bbl from hedging activities. The first quarter of 2003 included an after-tax gain of $2 million in mark-to-market accruals and realized gains/losses for non-hedge commodity derivatives recorded by the Company's Northrock subsidiary, compared to an after-tax loss of $4 million in the same period a year ago. These positive factors were partially offset by higher dry hole costs, lower natural gas and liquids production, and higher DD&A rates, which reduced after-tax earnings by approximately $25 million, $15 million and $10 million, respectively. Dry hole costs were higher due to the Bohr prospect located on Mississippi Canyon Block 637 in the deepwater Gulf of Mexico. North America average net daily natural gas production was 858 MMcf/d in the first quarter of 2003 compared to 937 MMcf/d in the same period a year ago, which was a decrease of 8 percent. The average net daily liquids production was 88 MBbl/d in the first quarter of 2003 compared to 99 MBbl/d in the same period a year ago, which was a decrease of 11 percent. This decrease was primarily attributable to natural declines in existing fields in the Gulf of Mexico and included the impact of about 5 MBOE/d from the divestiture of various properties in Canada, onshore U.S. and the Gulf of Mexico. Natural gas production in Alaska decreased 40 percent from a year ago due to natural declines in existing fields. 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. First Quarter Results: Earnings from continuing operations totaled $142 million in the first quarter of 2003 compared to $102 million in the same period a year ago, which was an increase of $40 million. The increase was due to $35 million in higher liquids prices, $10 million in higher natural gas prices and $10 million in higher natural gas production. These positive factors were partially offset by approximately $10 million in higher DD&A expense (including asset retirement obligation accretion). The average liquids price for International operations was $30.11 per Bbl in the first quarter of 2003, which was an increase of $10.25 per Bbl, or 52 percent, from the same period a year ago. -30- The average natural gas price for International operations was $2.77 per Mcf, which was an increase of 19 cents, or 7 percent, from the same period a year ago. Natural gas production in International operations was 982 MMcf/d in the first quarter of 2003 compared to 897 MMcf/d in the same period a year ago. This increase was primarily the result of higher demand from Thailand and Bangladesh. TRADE The Trade segment externally markets the majority of the Company's worldwide liquids production, excluding that of Pure, and North American natural gas production, excluding that of Pure and 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. First Quarter Results: The results for the first quarter of 2003 were a loss of $9 million after-tax from continuing operations compared to after-tax earnings of $1 million in the same period a year ago. The lower results reflect losses from crude oil and natural gas trading activities, which were negatively impacted by extremely volatile commodity prices experienced during the first quarter of 2003. Sales and operating revenues were $920 million in the first quarter of 2003 compared to $456 million in the same period a year ago, which was an increase of $464 million. These revenues represented approximately 52 percent and 45 percent of the Company's total sales and operating revenues for the first quarters of 2003 and 2002, respectively. In the first quarter of 2003, crude oil revenues increased by approximately $210 million and natural gas revenues increased by approximately $255 million, primarily due to higher commodity prices. 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. First Quarter Results: Earnings from continuing operations totaled $18 million in the first quarter of 2003 compared to $19 million in the same period a year ago. The decrease was due primarily to $3 million in expenses related to the construction of the Baku-Tbilisi-Ceyhan ("BTC") pipeline project. This negative factor was mostly offset by improved results in the gas storage business. 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. First Quarter Results: Earnings from continuing operations totaled $12 million in the first quarter of 2003 compared to $6 million in the same period a year ago. The current period results benefited from the impact of higher power generation in Indonesia under the amended Salak agreements. The first quarter of 2002 included net losses related to the Company's equity interest in natural gas-fired power plants in Thailand. -31- 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. First Quarter Results: The results for the first quarter of 2003 was a loss of $96 million compared to a loss of $95 million in the same period a year ago. The results in the first quarter of 2003 for the carbon, minerals and real estate business activities were $6 million lower than the same period a year ago. In addition, the first quarter of 2003 reflected approximately $5 million in higher pension related expenses. Lower after-tax expenses for environmental and litigation matters benefited the first quarter of 2003, with expenses of $17 million after-tax compared to $23 million after-tax for the same period a year ago. Net interest expense was $6 million lower in the first quarter of 2003 compared to the same period a year ago, primarily due to higher capitalized interest on development projects. FINANCIAL CONDITION Cash flows from operating activities, including working capital and other changes, were $685 million for the three months ended March 31, 2003, compared with $271 million for the same period a year ago. The increase principally reflected the effects of higher worldwide commodity prices. Pre-tax proceeds from asset sales were $66 million for the three months ended March 31, 2003. The Company completed the sale of various properties in Canada, onshore U.S. and the Gulf of Mexico, which netted the Company $64 million in proceeds. Pre-tax proceeds from asset sales for the three months ended March 31, 2002, including those classified as discontinued operations, were $30 million and primarily reflect the sale by the Company's Pure subsidiary of oil and gas producing properties in the U.S. Capital expenditures were $429 million for the first quarter of 2003 compared with $390 million in the same period a year ago. Capital expenditures for 2003 are currently forecast at approximately $1.7 billion, essentially unchanged from 2002. In the first quarter of 2003, the Company's capital expenditures included approximately $215 million for the development of undeveloped proved oil and gas reserves. The Company's total consolidated debt, including current maturities, at March 31, 2003, was $2.92 billion, compared with $3.0 billion at the end of 2002. This decrease primarily reflected the retirement of $89 million in 9.25% debentures which matured during the first quarter and $10 million of maturing medium-term notes (see note 10 for further detail on the Company's long-term debt). Cash and cash equivalents on hand totaled $356 million at March 31, 2003, up from $168 million at the end of 2002. The Company has two credit facilities in place: a $400 million 364-day credit agreement and a $600 million 5-year credit agreement. 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 March 31, 2003, the borrowing under the credit facility translated to $201 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. Further, the Company has substantial borrowing capacity to enable it to meet unanticipated cash requirements. -32- 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 March 31, 2003, the Company had sold $33 million of its domestic trade receivables under its accounts receivable securitization program, which was a decrease of $75 million from the $108 million level that was sold at year-end 2002. The Company also had in place a universal shelf registration statement as of March 31, 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. Moody's and Standard & Poor's outlooks remained stable for the Company's Prime-2 and A-2 commercial paper ratings, respectively. The Company does not believe it has a significant exposure to liquidity risk in the event of a credit rating downgrade. 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 March 31, 2003, the Company's remediation reserve totaled $249 million, of which $131 million was included in current liabilities. During the three months ended March 31, 2003, cash payments of $11 million were applied against the reserve and $15 million in provisions were 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 $215 million. The Company's total environmental reserve and possible additional liability amounts are grouped into the following four categories.
At March 31, 2003 ---------------------------- Possible Additional Millions of dollars Reserve Costs - -------------------------------------------------------------------------------- Superfund and similar sites $ 17 $ 10 Active Company facilities 34 25 Company facilities sold with retained liabilities and former Company-operated sites 102 80 Inactive or closed Company facilities 96 100 - -------------------------------------------------------------------------------- Total $ 249 $ 215 ================================================================================
Also see notes 12 and 13 to the consolidated financial statements in Item 1 of this report for additional information on environmental related matters. -33- In the first quarter of 2003, provisions of $11 million were recorded for the "Inactive or closed Company facilities" category of sites, primarily for remediation projects at the Company's former refinery in Beaumont, Texas. 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 quarter, Company recorded a provision for the revised estimated costs of the impoundment closure plan based on the TCEQ initial draft permit that was issued in the first quarter. In the first quarter of 2003, estimated possible additional remediation costs decreased by $30 million. The net decrease was primarily for sites in the "Active Company facilities" category. This decrease was the 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). Possible additional remediation costs for the "Inactive or closed Company facilities" category decreased by $5 million. This decrease was related to estimated remediation costs for the Company's former Beaumont, Texas refinery. Previously identified possible additional costs were included in the reserve for this site in the first quarter of 2003 as discussed above. Partially offsetting the foregoing decreases was an increase of $5 million in possible additional costs for the "Company facilities sold with retained liabilities and former Company-operated sites" category. 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. 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 foward-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 recent events concerning Iraq, Nigeria and Venezuela, security and other factors. The Company currently estimates its full-year 2003 production to average between 475,000 to 490,000 BOE per day. This production forecast includes the associated production loss of approximately 5,000 BOE per day from divestitures that the Company has completed so far this year. The Company has additional property divestitures pending or planned and additional adjustments to the production forecast range will be made as further divestitures are completed. The production forecast reflects the start of new oil production from the West Seno field in Indonesia, currently scheduled to begin late in the second quarter of 2003. 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, and production and exploration performance in the Gulf of Mexico. For the remaining three quarters of 2003, the Company has hedged 43.4 billion Btus of Lower 48 natural gas production with collars of $3.98 to $4.84 per MMBtu. This volume represents approximately 25 percent of expected Lower 48 natural gas production. The Company has hedged 1.5 million barrels of Lower 48 crude oil with collars between $28.94 and $32.71 per barrel in the second quarter of 2003, which represents 35 percent of -34- expected Lower 48 crude oil production. Hedged crude oil production volumes beyond the second quarter levels are immaterial. Based on current prices, the Company's net earnings for the full-year are expected to change 14 cents per share for each $1 change in the Company's average worldwide realized price for crude oil and 7 cents per share for every 10-cent change in its average realized North America natural gas price, excluding the effect of hedging activities. The Company forecasts pre-tax dry hole costs of $155 million to $185 million and that pre-tax pension-related expenses will increase over 2002 by approximately $55 million to $60 million. Exploration and Production - North America U.S. Lower 48 The Company had two discoveries late in 2002 and one in 2003 in the deep shelf in the Gulf of Mexico, and it expects to continue its deep shelf program in the Gulf of Mexico with 9 to 15 additional wells in the remaining months of 2003. In the Gulf of Mexico deepwater, the Company plans to continue funding the development of the Mad Dog discovery in which the Company has a 15.6 percent non-operating working interest. The Company anticipates first production in late 2004 or early 2005, with gross expected production of 75 MBbl/d of liquids and 35 MMcf/d of natural gas in 2007. The Company expects the co-venture integrated project team of the K-2 discovery to have a development plan in 2003. The Company also expects to drill 2 or 3 more wells in the Gulf of Mexico deepwater in the remaining months of 2003. The Company is currently drilling the Champlain prospect located on the Atwater Valley Block 63. The Company is participating in an appraisal well, which will earn it a 30 percent interest in the discovery by paying for 50 percent of the well costs. The Champlain prospect is strategic to the Company because of its proximity to the Mirage discovery, located on Mississippi Canyon Block 941, where it has a 25 percent non-operating working interest. The Company continues to move forward with studies on development options for its Trident discovery in the deepwater Gulf of Mexico. The Company is having conversations 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. The Company has sold and anticipates selling more of its lower margin properties in the U.S. in 2003. Alaska The Ninilchik Unit development in the South Kenai Peninsula is progressing. First production from the Ninilchik Unit is also expected in the fourth quarter of 2003, with that early production going to the Kenai Gas Storage Facility for delivery to customers beginning in the first quarter of 2004. The Company has a 40 percent non-operating interest in the unit. The Company is also planning to drill at least one new exploration well on the Kenai Peninsula in 2003. Exploration and Production - International Far East Thailand: Demand for natural gas from the Company's fields has been very strong as a result of the ongoing reduced production from adjacent fields operated by PTT Exploration and Production PLC ("PTTEP"), and the Company expects that demand to continue. The Company expects higher average liquids production, with the full-year effect of crude oil production from its Yala field. The Company has a 71 percent working interest in the Yala field (62 percent net of royalty). The Company's plans are geared towards exploring for additional oil and gas resources in the Gulf of Thailand and supporting the efforts of 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. -35- Indonesia: The Company expects new production from the deepwater West Seno oil and gas field to come on line in late June or early July 2003. Gross daily production from the first phase of development is expected to reach about 35 MBOE to 40 MBOE by the end of 2003, increasing to a peak production level of approximately 60 MBbl/d of oil and 150 MMcf/d of natural gas (gross) in late 2005 with the second phase of development. 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 $300 million for the first phase, and the other loan is $50 million for the second phase. The loan associated with the second phase is still subject to a final construction contract being obtained. The Company's Unocal Rapak, Ltd. ("Unocal Rapak"), subsidiary is continuing its evaluation of engineering and development studies for the deepwater Ranggas oil prospect offshore East Kalimantan, Indonesia. The Company expects to complete the pre-development engineering to determine if Ranggas is a commercial development later in 2003. Unocal Rapak is operator of the Rapak PSC area and holds an 80 percent working interest. The Company began testing the oil potential of structures south of the main Ranggas discovery area in the second quarter of 2003. The Company is also evaluating early development options for the condensate discovered at its deepwater Gendalo-Gandang discovery in the Ganal PSC, offshore East Kalimantan. The Company's Unocal Ganal, Ltd., subsidiary is the operator of the Ganal PSC and holds an 80 percent working interest. The Company will drill a deep 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 Company holds a 50 percent working interest in the well. The Company is also participating in the Donggala PSC, in which it had acquired a 19.55% non-operating working interest in early 2003. The Donggala PSC lies adjacent to and east of the Rapak PSC area. China: The Company has worked with China National Offshore Oil Corporation, 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 is continuing its negotiations and is still expecting to sign PSCs in 2003 to explore and develop natural gas resources. The Company's working interest is expected to be 20 percent. 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 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 expected project financing from international lending institutions like the IFC and EBRD and from several export credit agencies, should help to mitigate the political risk. Bangladesh: Domestic sales in the country have expanded and the Company is working on amending agreements to increase the Take-or-Pay volume for natural gas sold to Petrobangla, the state oil and gas company. 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 April 30, 2003, the Company's business unit in Bangladesh had a gross receivable balance of approximately $29 million relating to invoices billed for natural gas and condensate sales to Petrobangla. Approximately $23 million of the -36- outstanding balance represented past due amounts and accrued interest for invoices covering November 2002 through March 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. Midstream Physical construction of the BTC pipeline began in April 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 the pipeline 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 Kenai Kachemak Pipeline, currently under construction, will transport natural gas from Ninilchik to Kenai, where it will tie into the existing gas grid serving south central Alaska. The Company expects the 32-mile pipeline to be in operation in the fourth quarter of 2003. 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, the Power Sector Assets and Liabilities Corporation and the Philippine Department of Energy signed a compromise settlement agreement covering the definitive terms of settlement in March 2003. The parties are now in the process of securing all necessary Philippine government and court approvals of the settlement. Major flooding and landslides caused by heavy rains at the Gunung Salak geothermal project area on Java in Indonesia during early May has resulted in damage to some of geothermal steam production and electric power generation and transmission facilities. As a result of the damage, electricity generation for the second and third quarters of 2003 is expected to be reduced significantly. The Company is currently assessing the full impact of the damage, alternative repair options and the anticipated impact on segment earnings. The Company is in discussions with PT. PLN (Persero) concerning the Sarulla geothermal project in the island of Sumatra, Indonesia. FUTURE ACCOUNTING CHANGES FASB Interpretation No. 46: Effective January 1, 2003, the Company adopted FASB Interpretation No. 46, "Consolidation of Variable Interest Entities." (see note 2 to the consolidated financial statements in Item 1 of this report). The effective date for the consolidation of entities existing prior to February 1, 2003 is July 1, 2003. The Company expects the adoption of the recognition (i.e., consolidation) requirements of the Interpretation to increase its consolidated long-term debt by approximately $320 million in the third quarter of 2003. This amount will include $242 million related to a partnership interest in which the Company currently has a minority interest liability (see note 11 to the consolidated financial statements in Item 1 of this report) and $78 million of third-party debt of DSPL (see note 11 to the consolidated financial statements in Item 1 of this report). SFAS No. 149: In April 2003, the FASB issued 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. SFAS No. 149 is effective for contracts entered into or modified after June 30, 2003. The Company is currently in the process of evaluating the impact of this pronouncement. 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. -37- 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 March 31, 2003. Assuming a ten percent decrease in the Company's weighted average borrowing costs at March 31, 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 $100 million at March 31, 2003. -38- 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. 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 March 31, 2003, the Company had various foreign currency swaps and foreign currency forward contracts outstanding related to operations in Canada, 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 swaps and forward contracts. Assuming an adverse change of ten percent in foreign exchange rates at March 31, 2003, the potential decrease in fair value of the Company's foreign currency forward contracts, foreign-currency denominated debt, foreign currency swaps and foreign currency forward contracts of its subsidiaries, would have been approximately $34 million at March 31, 2003. 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 $15 million at March 31, 2003. The value at risk related to hydrocarbon derivatives held for non-hedging purposes was approximately $5 million at March 31, 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 March 31, 2003, along with the fair values of those instruments. -39-
Open Hydrocarbon Hedging Derivative Instruments (a) (Thousands of dollars) 2003 2004 2005 2006 2007-2008 Fair Value Asset(Liability)(b)(c) - ------------------------------------------------------------------------------------------------------------------------------------ Natural Gas Futures Positions Volume (MMBtu) 530,000 - - - - $ 1,385 Average price, per MMBtu $ 4.99 - ------------------------------------------------------------------------------------------------------------------------------------ Natural Gas Swap Positions Pay fixed price Volume (MMBtu) 5,953,000 7,511,000 7,218,000 7,218,000 14,459,000 $ 60,701 Average swap price, per MMBtu $ 2.58 $ 2.43 $ 2.37 $ 2.42 $ 2.50 Receive fixed price Volume (MMBtu) - - - - - $ 2,458 Average swap price, per MMBtu $ - - ------------------------------------------------------------------------------------------------------------------------------------ Natural Gas Basis Swap Positions Volume (MMBtu) 16,180,000 - - - - $ 2,000 Average price received, per MMBtu $ 4.82 Average price paid, per MMBtu $ 4.70 - ------------------------------------------------------------------------------------------------------------------------------------ Natural Gas Collar Positions Volume (MMBtu) 38,426,000 268,500 - - - $ (27,021) Average ceiling price, per MMBtu $ 4.66 $ 5.45 Average floor price, per MMBtu $ 3.79 $ 2.82 - ------------------------------------------------------------------------------------------------------------------------------------ Natural Gas Option (OTC) Put Volume (MMBtu) (21,400,000) - - - - $ 2,185 Average Put Price $ 3.25 - ------------------------------------------------------------------------------------------------------------------------------------ - ------------------------------------------------------------------------------------------------------------------------------------ Crude Oil Future position Volume (Bbls) (815,000) - - - - $ (714) Average price, per Bbl $ 31.45 - ------------------------------------------------------------------------------------------------------------------------------------ Crude Oil Option Put Volume (Bbls) (1,600,000) (720,000) - - - $ (413) Average price, per Bbl $ 24.00 $ 20.00 - ------------------------------------------------------------------------------------------------------------------------------------ Crude Oil Collar Positions Volume (Bbls) 2,511,500 810,000 - - - $ 1,703 Average ceiling price, per Bbl $ 32.70 $ 28.16 Average floor price, per Bbl $ 28.42 $ 23.41 - ------------------------------------------------------------------------------------------------------------------------------------ (a) Positions reflect long (short) volumes. (b) Net claims against counterparties with non-investment grade credit ratings are immaterial. (c) Includes $6,754 thousand in assumed liabilities which were capitalized as acquisition costs.
-40-
Open Hydrocarbon Non-Hedging Derivative Instruments (a) (Thousands of dollars) 2003 2004 Fair Value Asset(Liability) (b) - ----------------------------------------------------------------------------------------------- --------------- -------------------- Natural Gas Futures Positions Volume (MMBtu) 5,500,000 - $ (6,739) Average price, per MMBtu $ 5.50 - ------------------------------------------------------------------------------------------------------------------------------------ Natural Gas Swap Positions Pay fixed price Volume (MMBtu) 6,360,000 - $ 175 Average swap price, per MMBtu $ 5.20 Receive fixed price Volume (MMBtu) 5,091,375 95,438 $(11,502) Average swap price, per MMBtu $ 4.59 $ 1.99 - ------------------------------------------------------------------------------------------------------------------------------------ Natural Gas Basis Swap Positions Volume (MMBtu) 16,500,000 - $ 4,520 Average price received, per MMBtu $ 4.82 $ - Average price paid, per MMBtu $ 4.52 $ - - ------------------------------------------------------------------------------------------------------------------------------------ Natural Gas Spread Swap Positions Volume (MMBtu) 3,510,000 3,640,000 $ 4,044 Average price received, per MMBtu $ 0.59 $ 0.54 Average price paid, per MMBtu $ 0.79 $ 1.46 - ------------------------------------------------------------------------------------------------------------------------------------ Natural Gas Option (Listed) Call Volume (MMBtu) (6,250,000) - $ 2,023 Average Call price $ 6.08 $ - Put Volume (MMBtu) (1,600,000) - $ (1,244) Average Put Price $ 5.97 $ - - ------------------------------------------------------------------------------------------------------------------------------------ Natural Gas Option (Over the Counter) Call Volume (MMBtu) (3,650,700) - $ (5,542) Average Call price $ 4.08 $ - Put Volume (MMBtu) (3,940,000) (1,820,000) $ (39) Average Put price $ 3.97 $ 4.50 - ------------------------------------------------------------------------------------------------------------------------------------ Natural Gas Spread Option (Over the Counter) NYMEX / IFERC (c) Call Volume (MMBtu) (1,000,000) - $ 49 Average Strike price $ 0.60 $ - Put Volume (MMBtu) (7,000,000) - $ 158 Average Strike price $ 0.25 $ - - ------------------------------------------------------------------------------------------------------------------------------------ - ------------------------------------------------------------------------------------------------------------------------------------ Crude Oil Future position Volume (Bbls) 721,000 - $ 349 Average price, per Bbl $ 35.27 - ------------------------------------------------------------------------------------------------------------------------------------ Crude Oil Option Put Volume (Bbls) - - $ (230) Average price, per Bbl $ - Call Volumes (Bbls) (100,000) - $ 255 Average price, per Bbl $ 42.50 - ------------------------------------------------------------------------------------------------------------------------------------ Crude Oil Option (Calender Spread) Put Volume (Bbls) 200,000 - $ (138) Average price, per Bbl $ 0.80 $ - Call Volumes (Bbls) (200,000) - $ (8) Average price, per Bbl $ 0.93 $ - - ------------------------------------------------------------------------------------------------------------------------------------ Crude Oil Swap Positions Pay fixed price Volume (Bbls) (4,559,540) - $ (3,048) Average swap price, per Bbl $ 30.45 Receive fixed price Volume (Bbls) 3,959,540 - $ 3,997 Average swap price, per Bbl $ 30.69 - ------------------------------------------------------------------------------------------------------------------------------------ (a) Positions reflect long (short) volumes. (b) Includes $7,476 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).
-41- ITEM 4. CONTROLS AND PROCEDURES Within the 90 days prior to the date of 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-14 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 were no significant changes in the Company's internal controls or other factors that could significantly affect these controls subsequent to the date of their evaluation and there were no corrective actions required with regard to significant deficiencies and material weaknesses. -42- 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. There is incorporated by reference: the information regarding the environmental remediation reserve and possible additional remediation costs in notes 12 and 13 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 13 to the consolidated financial statements. Information with respect to recent developments in certain previously reported proceedings is set forth below: 1. In the California Superior Court cases (the Doe and Roe cases) alleging the Company's liability in connection with the construction of the natural gas pipeline from the Yadana field across Myanmar to the Thailand border, described in Paragraph 2 of Item 3 of the 2002 Form 10-K, the court has bifurcated the trial. Phase I will address choice of law and whether the correct corporate defendants are before the court. If Unocal is unsuccessful in Phase I, then Phase II will address liability. Phase I is scheduled for July 2003 and Phase II for December 2003. The Company believes that the outcomes of the federal and state cases are not likely to have a material adverse effect on the Company's financial condition or liquidity or, based on management's current assessment of the cases, the Company's results of operations. Certain Environmental Matters Involving Civil Penalties 2. The Environmental Protection Agency ("EPA") and Unocal have entered into a civil settlement 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 waste in Cook Inlet. The EPA claimed that Unocal violated the permit conditions in 65 separate instances at 11 different facilities located in Cook Inlet, Alaska. Some of the alleged violations include a monthly reporting period, and therefore qualify as daily violations for the entire standard 30-day month. The alleged violations consist of procedural failures such as failure to take samples or errors in reporting sample testing, and substantive failures such as discharges which exceeded the permit limits. On May 8, 2003, Unocal and the EPA have executed a Consent Agreement with respect to each affected facility. The settlement will be noticed in an Anchorage, Alaska, newspaper, and will be subject to public comment before final approval. The total amount of the fine imposed pursuant to the settlement agreement is $370,000, of which Unocal will pay $189,389 and the remainder will be paid by working interest owners in the affected facilities. -43- ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K. (a) Exhibits: The Exhibit Index on page 48 of this report lists the exhibits that are filed as part of this report. (b) Reports on Form 8-K: Filed during the first quarter of 2003: (1) Current Report on Form 8-K, dated January 28, 2003 and filed February 5, 2003, for the purpose of reporting, under Item 5, the Company's fourth quarter and full-year 2002 earnings and related information, the Company's 2002 reserve replacement and finding development and acquisitions costs, the Company's 2003 outlook and other operational activity updates. (2) Current Report on Form 8-K, dated February 4, 2003 and filed February 10, 2003, for the purpose of reporting, under Item 5, the Company's designation of its Vice President and Chief Legal Officer as an "executive officer." (3) Current Report on Form 8-K, dated March 26, 2003 and filed April 1, 2003, for the purpose of reporting, under Item 5, the Company's drilling results of a well in the Gulf of Mexico, and under Item 7, the amendments and interpretations of certain compensation plans. Filed during the second quarter of 2003 to the date hereof: (1) Current Report on Form 8-K, dated April 1, 2003, and filed April 2, 2003, for the purpose of reporting, under Item 5 and Item 7, an amendment to Unocal's Rights Agreement. (2) Current Report on Form 8-K, dated April 24, 2003, and filed April 28, 2003, for the purpose of reporting, under Item 5, the Company's first quarter 2003 earnings and related information and the Company's 2003 outlook. -44- 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: May 12, 2003 By: /s/JOE D. CECIL ------------------------------ Joe D. Cecil Vice President and Comptroller (Duly Authorized Officer and Principal Accounting Officer) -45- 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 quarterly 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 quarterly report; 3. Based on my knowledge, the financial statements, and other financial information included in this quarterly 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 quarterly 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-14 and 15d-14) for the registrant and we have: (a) designed such disclosure controls and procedures 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 quarterly report is being prepared; (b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and (c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions): (a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and (b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officer and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: May 12, 2003 /s/CHARLES R. WILLIAMSON ---------------------------- Charles R. Williamson Chairman of the Board and Chief Executive Officer -46- 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 quarterly 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 quarterly report; 3. Based on my knowledge, the financial statements, and other financial information included in this quarterly 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 quarterly 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-14 and 15d-14) for the registrant and we have: (a) designed such disclosure controls and procedures 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 quarterly report is being prepared; (b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and (c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions): (a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and (b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officer and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: May 12, 2003 /s/ TERRY G. DALLAS --------------------------- Terry G. Dallas Executive Vice President and Chief Financial Officer -47- EXHIBIT INDEX 10.1 Amendment No. 3 to Rights Agreement between Unocal and Mellon Investor Services, L.L.C., as Rights Agent dated as of April 1, 2003 (incorporated by reference to Exhibit 10 to Unocal's Current Report on Form 8-K dated April 1, 2003, File No. 1-8483). 10.2 Form of Director Indemnity Agreement between Unocal and each of its directors. 10.3 Form of Officer Indemnity Agreement (restated) between Unocal and each of its officers which had existing Indemnity Agreements. 10.4 Form of Officer Indemnity Agreement (new) between Unocal and each of its officers which did not have existing Indemnity Agreements. 10.5 Amendments and interpretations of certain compensation plans effective October 1, 2002 (incorporated by reference to Exhibit 10 to Unocal's Current Report on Form 8-K dated March 26, 2003, File No. 1-8483). 12.1 Statement regarding computation of ratio of earnings to fixed charges of Unocal Corporation for the three months ended March 31, 2003 and 2002. 12.2 Statement regarding computation of ratio of earnings to fixed charges of Union Oil Company of California for the three months ended March 31, 2003 and 2002. Copies of exhibits will be furnished upon request. Requests should be addressed to the Corporate Secretary. -48- EX-10 3 ex10-2.txt EX 10.2 DIRECTOR INDEMNITY AGREEMENT Exhibit 10.2 UNOCAL CORPORATION DIRECTOR INDEMNITY AGREEMENT This Unocal Corporation Director Indemnity Agreement ("Agreement") is made as of March 26, 2003 by and between Unocal Corporation, a Delaware corporation (the "Corporation"), and [Name of Director] (the "Director") with reference to the following facts: RECITALS A. The Corporation and the Director have previously entered into a Unocal Corporation Director Indemnity Agreement and a Unocal Corporation Director Insurance Agreement (jointly, the "Old Agreements") setting forth terms and conditions under which the Corporation provides indemnification and insurance to the Director. B. The Corporation and the Director are entering into this Agreement, which amends and restates the Old Agreements, in order to update the terms and conditions under which the Corporation provides indemnification and insurance to the Director. C. It is essential to the Corporation to retain and attract as directors the most capable persons available. D. It is now and has been the express policy of the Corporation to indemnify and insure its directors so as to provide them with the maximum possible protection permitted by law. E. The Director is currently a member of the Board of Directors of the Corporation and is performing valuable services for the Corporation. The Corporation wishes the Director to continue in such capacity, and the Director is willing, under certain circumstances, to continue in such capacity. F. The Corporation's Certificate of Incorporation, as permitted by Section 102(b)(7) of the Delaware General Corporation Law, limits the Director's liability to the Corporation and its stockholders for monetary damages for certain breaches of fiduciary duty. G. The Bylaws of the Corporation provide for the indemnification of the directors of the Corporation to the maximum extent authorized by Section 145 of the Delaware General Corporation Law, as amended or as may be amended, revised or superseded. H. In addition to the indemnification to which the Director is entitled pursuant to the Certificate of Incorporation and Bylaws of the Corporation and as additional consideration for the Director's services, the Corporation has, in the past, furnished at its expense director and officer liability insurance ("Insurance"). Many insurance carriers, as a condition of issuing Insurance policies, are requiring that corporations protect directors and officers from liability to the maximum extent permitted by law. I. The Director has indicated that he or she does not regard the Corporation's Certificate of Incorporation, the indemnities available under the Corporation's Bylaws, and the Insurance currently in effect as adequate to protect him or her against the risks associated with his or her services to the Corporation. The Director may not be willing to continue in office in the absence of the further lawful protection afforded by the instant Agreement. AGREEMENT NOW, THEREFORE, in order to induce the Director to continue to serve as a director of the Corporation and of certain subsidiaries and affiliates of the Corporation, in consideration for his or her continued services, and in order to do everything possible to procure and maintain adequate Insurance policies, the parties hereby agree as follows: 1. As of the date hereof, the Old Agreements shall be amended and restated to read in their entirety as set forth in this Agreement. 2. Subject only to the limitations set forth in Section 4, the Corporation will pay on behalf of the Director and his or her heirs, executors, administrators or assigns any Expenses (as defined below) actually and reasonably incurred by the Director because of any threatened, pending or completed action, suit, proceeding, inquiry, hearing or investigation, whether brought by or in the right of the Corporation or otherwise and whether of a civil, criminal, administrative or investigative nature (a "Proceeding"), resulting from any act or omission or neglect or breach of duty, including any actual or alleged error or misstatement or misleading statement, which he or she commits or suffers while acting in his or her capacity as a director of the Corporation or, at the request of the Corporation, acting as a director, officer, trustee, fiduciary, employee, or agent (collectively, "Agent") of another foreign or domestic corporation, limited liability company, partnership, joint venture, trust, or any other enterprise or entity whatsoever, including without limitation, employee benefit plans (collectively, "Affiliate"), or by reason of the fact that the Director is or was a director of the Corporation or is or was serving at the request of the Corporation as an Agent of an Affiliate, whether the basis of such Proceeding is alleged action in an official capacity, or in any other capacity, to the fullest extent authorized by law, including but not limited to the Delaware General Corporation Law, as the same exists on the date hereof or as may hereafter be amended (but, in the case of any such amendment, only to the extent that such amendment permits the Corporation to provide broader indemnification rights than said law permitted the Corporation to provide prior to such amendment); provided, however, that except with respect to a Proceeding seeking to enforce rights to indemnification hereunder, the Corporation shall indemnify the Director with respect to a Proceeding initiated by the Director only if such Proceeding was authorized by the Board of Directors of the Corporation. 3. The payments (the "Expenses") which the Corporation will be obligated to make hereunder shall include any expense, liability or loss of the Director, including without limitation, damages, judgments, fines, ERISA excise taxes, penalties, amounts paid or to be paid in settlement or in costs by or on behalf of the Director, expenses relating to investigations or to judicial or administrative proceedings or appeals, attorneys' fees or any other costs of defense of legal actions, claims, or proceedings or appeals therefrom, costs of attachment or similar bonds, and any other amounts actually incurred or suffered by the Director in connection with any 2 Proceeding or in establishing a right of indemnification under this Agreement. The Corporation shall advance to the Director as soon as practicable any Expenses incurred by the Director upon receipt by the Corporation of an undertaking, if such undertaking is required by law, by or on behalf of the Director to repay all amounts so advanced if the Director is not entitled to be indemnified by the Corporation pursuant to this Agreement or otherwise, as decided by a court, arbitrator or other judicial agent having the requisite legal authority to make such a decision, which decision has become final and from which no appeal or other review proceeding is permissible. 4. The Corporation shall not be obligated under this Agreement to make any payment of Expenses to the Director: (a) the payment of which is prohibited by Delaware law; (b) for which and to the extent payment is actually and unqualifiedly made to the Director under an insurance policy or otherwise; or (c) based upon or attributable to the Director gaining in fact any personal profit or advantage to which he or she was not legally entitled, as decided by a court, arbitrator or other judicial agent having the requisite legal authority to make such a decision, which decision has become final and from which no appeal or other review proceeding is permissible. 5. If a claim under this Agreement is not paid by the Corporation, or on its behalf, within sixty (60) days after a written claim has been received by the Corporation (except in the case of a claim for the advancement of Expenses incurred in a Proceeding in advance of its final disposition, in which case the applicable period shall be twenty (20) days), the Director may at any time thereafter bring suit against the Corporation to recover the unpaid amount of the claim, and if successful in whole or in part in such suit or in a suit brought by the Corporation to recover an advancement of Expenses pursuant to the terms of an undertaking, the Director shall also be entitled to be paid the Expenses of prosecuting or defending such claim. The right to indemnification or advances as provided by this Agreement shall be enforceable by the Director in any court of competent jurisdiction. The Corporation's sole defense to an action by the Director seeking indemnification shall be that the Director has not met the standard of conduct which makes it permissible under the Delaware General Corporation Law for the Corporation to indemnify the Director for the amount claimed, and the burden of proving such defense shall be on the Corporation; provided, however, that in the case of a claim for the advancement of Expenses incurred in a Proceeding in advance of its final disposition where the required undertaking, if any is required, has been tendered to the Corporation, that defense shall not be available to the Corporation. Neither the failure of the Corporation (including the Board of Directors, its independent legal counsel or its stockholders) to have made a determination prior to the commencement of such action that indemnification of the Director is proper under the circumstances because he or she has met the applicable standard of conduct set forth in the Delaware General Corporation Law, nor an actual determination by the Corporation (including the Board of Directors, its independent legal counsel or its stockholders) that the Director has not 3 met such applicable standard of conduct, shall be a defense to the action or create a presumption that the Director has not met the applicable standard of conduct. 6. The Corporation shall maintain in full force and effect, at its own expense, Insurance coverage for the Director in amounts and scope at least as favorable as that maintained by the Corporation on September 30, 1996, or, to the extent more favorable, any Insurance policy entered into or renewed by the Corporation following such date. Notwithstanding the foregoing, if (a) the Corporation, after using its best efforts, cannot obtain and purchase such coverage for an amount no more than what it paid for the most recent expiring Insurance policy plus a reasonable additional amount and (b) the Corporation has so notified the Director at the most recent address the Corporate Secretary has for the Director, then the Corporation shall only be required to purchase such Insurance coverage for any act or omission occurring at or prior to the time of such notification or, if more favorable to the directors and officers of the Corporation as a whole, such Insurance coverage as is standard within the Corporation's industry. Such obligation shall continue for so long as the Director may be subject to any possible claim which might be covered under such Insurance coverage. The Corporation agrees that money damages would not be a sufficient remedy for any breach of this provision and that the Director shall be entitled to specific performance and injunctive or other equitable relief as remedies for any such breach. Such remedies shall not be deemed to be the exclusive remedies of the Director, and shall be in addition to all other remedies available at law or in equity to the Director. The Corporation waives any requirement for the securing or posting of any bond in connection with any such remedy. 7. The Director shall give the Corporation and any insurance company providing Insurance coverage such information and cooperation in the defense of a Proceeding as they may reasonably require and as shall be within the Director's power; provided, however, that if a Proceeding is brought by the Corporation, or if the Corporation is assisting or cooperating in the prosecution of a Proceeding against the Director, the Director shall only be required to provide information to and cooperate with any insurance company providing Insurance coverage. 8. The Director shall give to the Corporation notice as soon practicable of any Proceeding for which indemnity will or could be sought under this Agreement, the Corporation's Bylaws or any other obligation whatsoever of the Corporation to indemnify the Director or for which Insurance coverage could be available. 9. Nothing herein shall be deemed to diminish or otherwise restrict the Director's right to indemnification under any provision of the Certificate of Incorporation or Bylaws of the Corporation, under Delaware law or under any other obligation whatsoever of the Corporation to indemnify the Director. 10. In the event of payment under this Agreement, the Corporation shall be subrogated to the extent of such payment to all of the rights of recovery of the Director, who shall execute all papers required and shall do everything that may be necessary to secure such rights, including the execution of such documents necessary to enable the Corporation effectively to bring suit to enforce such rights. 4 11. The provisions of this Agreement shall be severable in the event that any of the provisions hereof are held by a court of competent jurisdiction to be invalid, void or otherwise unenforceable, and the remaining provisions shall remain enforceable to the fullest extent permitted by law. Furthermore, to the fullest extent permitted, the provisions of this Agreement shall be construed so as to give effect to the intent manifested by any provision held invalid, void or otherwise unenforceable. 12. This Agreement shall be binding upon all successors and assigns of the Corporation (including any transferee of all or substantially all of its assets and any successor by merger, consolidation or operation of law) and shall inure to the benefit of the heirs, personal representatives and estate of the Director. 13. This Agreement shall be governed by and construed in accordance with Delaware law. 14. The indemnification under this Agreement shall cover the Director's service as a director of the Corporation or as an Agent of an Affiliate and shall continue after he or she has ceased to act in such capacity with respect to all of his or her acts in such capacity, whether arising prior to, on or after the date of this Agreement. 15. No supplement, modification or amendment of this Agreement shall be binding unless executed in writing by the Corporation and the Director. No waiver of any of the provisions of this Agreement shall operate as a waiver of any other provisions of this Agreement, nor shall any waiver constitute a continuing waiver. Except as specifically provided in this Agreement, no failure to exercise or delay in exercising any right or remedy under this Agreement shall constitute a waiver of the right or remedy. 16. This Agreement may be executed in any number of counterparts, all of which taken together shall constitute one instrument. IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be duly executed and signed as of the day and year first above written. UNOCAL CORPORATION DIRECTOR: By______________________________________ ________________________ ____________________, Vice President [Name of Director] By______________________________________ ____________________, Secretary 5 EX-10 4 ex10-3.txt EX 10.3 OFFICER INDEMNITY AGREEMENT Exhibit 10.3 UNOCAL CORPORATION OFFICER INDEMNITY AGREEMENT This Unocal Corporation Officer Indemnity Agreement ("Agreement") is made as of March 26, 2003 by and between Unocal Corporation, a Delaware corporation (the "Corporation"), and [Name of Officer] (the "Officer") with reference to the following facts: RECITALS A. The Corporation and the Officer have previously entered into a Unocal Corporation Officer Indemnity Agreement (the "Old Agreement") setting forth terms and conditions under which the Corporation provides indemnification and insurance to the Officer. B. The Corporation and the Officer are entering into this Agreement, which amends and restates the Old Agreement, in order to update the terms and conditions under which the Corporation provides indemnification and insurance to the Officer. C. It is essential to the Corporation to retain and attract as officers the most capable persons available. D. It is now and has been the express policy of the Corporation to indemnify and insure its officers so as to provide them with the maximum possible protection permitted by law. E. The Officer is currently an officer of the Corporation and is performing valuable services for the Corporation. The Corporation wishes the Officer to continue in such capacity, and the Officer is willing, under certain circumstances, to continue in such capacity. F. The Bylaws of the Corporation provide for the indemnification of the officers of the Corporation to the maximum extent authorized by Section 145 of the Delaware General Corporation Law, as amended or as may be amended, revised or superseded. G. In addition to the indemnification to which the Officer is entitled pursuant to the Bylaws of the Corporation and as additional consideration for the Officer's services, the Corporation has, in the past, furnished at its expense director and officer liability insurance ("Insurance"). Many insurance carriers, as a condition of issuing Insurance policies, are requiring that corporations protect directors and officers from liability to the maximum extent permitted by law. H. The Officer has indicated that he or she does not regard the indemnities available under the Corporation's Bylaws and the Insurance currently in effect as adequate to protect him or her against the risks associated with his or her services to the Corporation. The Officer may not be willing to continue in office in the absence of the further lawful protection afforded by the instant Agreement. AGREEMENT NOW, THEREFORE, in order to induce the Officer to continue to serve as an officer of the Corporation and of certain subsidiaries and affiliates of the Corporation, in consideration for his or her continued services, and in order to do everything possible to procure and maintain adequate Insurance policies, the parties hereby agree as follows: 1. As of the date hereof, the Old Agreement shall be amended and restated to read in its entirety as set forth in this Agreement. 2. Subject only to the limitations set forth in Section 4, the Corporation will pay on behalf of the Officer and his or her heirs, executors, administrators or assigns any Expenses (as defined below) actually and reasonably incurred by the Officer because of any threatened, pending or completed action, suit, proceeding, inquiry, hearing or investigation, whether brought by or in the right of the Corporation or otherwise and whether of a civil, criminal, administrative or investigative nature (a "Proceeding"), resulting from any act or omission or neglect or breach of duty, including any actual or alleged error or misstatement or misleading statement, which he or she commits or suffers while acting in his or her capacity as an officer of the Corporation or, at the request of the Corporation, acting as a director, officer, trustee, fiduciary, employee, or agent (collectively, "Agent") of another foreign or domestic corporation, limited liability company, partnership, joint venture, trust, or any other enterprise or entity whatsoever, including without limitation, employee benefit plans (collectively, "Affiliate"), or by reason of the fact that the Officer is or was an officer of the Corporation or is or was serving at the request of the Corporation as an Agent of an Affiliate, whether the basis of such Proceeding is alleged action in an official capacity, or in any other capacity, to the fullest extent authorized by law, including but not limited to the Delaware General Corporation Law, as the same exists on the date hereof or as may hereafter be amended (but, in the case of any such amendment, only to the extent that such amendment permits the Corporation to provide broader indemnification rights than said law permitted the Corporation to provide prior to such amendment); provided, however, that except with respect to a Proceeding seeking to enforce rights to indemnification hereunder, the Corporation shall indemnify the Officer with respect to a Proceeding initiated by the Officer only if such Proceeding was authorized by the Board of Directors of the Corporation. 3. The payments (the "Expenses") which the Corporation will be obligated to make hereunder shall include any expense, liability or loss of the Officer, including without limitation, damages, judgments, fines, ERISA excise taxes, penalties, amounts paid or to be paid in settlement or in costs by or on behalf of the Officer, expenses relating to investigations or to judicial or administrative proceedings or appeals, attorneys' fees or any other costs of defense of legal actions, claims, or proceedings or appeals therefrom, costs of attachment or similar bonds, and any other amounts actually incurred or suffered by the Officer in connection with any Proceeding or in establishing a right of indemnification under this Agreement. The Corporation shall advance to the Officer as soon as practicable any Expenses incurred by the Officer upon receipt by the Corporation of an undertaking, if such undertaking is required by law, by or on behalf of the Officer to repay all amounts so advanced if the Officer is not entitled to be indemnified by the Corporation pursuant to this Agreement or otherwise, as decided by a court, arbitrator or other judicial agent having the requisite legal authority to make such a decision, 2 which decision has become final and from which no appeal or other review proceeding is permissible. 4. The Corporation shall not be obligated under this Agreement to make any payment of Expenses to the Officer: (a) the payment of which is prohibited by Delaware law; (b) for which and to the extent payment is actually and unqualifiedly made to the Officer under an insurance policy or otherwise; or (c) based upon or attributable to the Officer gaining in fact any personal profit or advantage to which he or she was not legally entitled, as decided by a court, arbitrator or other judicial agent having the requisite legal authority to make such a decision, which decision has become final and from which no appeal or other review proceeding is permissible. 5. If a claim under this Agreement is not paid by the Corporation, or on its behalf, within sixty (60) days after a written claim has been received by the Corporation (except in the case of a claim for the advancement of Expenses incurred in a Proceeding in advance of its final disposition, in which case the applicable period shall be twenty (20) days), the Officer may at any time thereafter bring suit against the Corporation to recover the unpaid amount of the claim, and if successful in whole or in part in such suit or in a suit brought by the Corporation to recover an advancement of Expenses pursuant to the terms of an undertaking, the Officer shall also be entitled to be paid the Expenses of prosecuting or defending such claim. The right to indemnification or advances as provided by this Agreement shall be enforceable by the Officer in any court of competent jurisdiction. The Corporation's sole defense to an action by the Officer seeking indemnification shall be that the Officer has not met the standard of conduct which makes it permissible under the Delaware General Corporation Law for the Corporation to indemnify the Officer for the amount claimed, and the burden of proving such defense shall be on the Corporation; provided, however, that in the case of a claim for the advancement of Expenses incurred in a Proceeding in advance of its final disposition where the required undertaking, if any is required, has been tendered to the Corporation, that defense shall not be available to the Corporation. Neither the failure of the Corporation (including the Board of Directors, its independent legal counsel or its stockholders) to have made a determination prior to the commencement of such action that indemnification of the Officer is proper under the circumstances because he or she has met the applicable standard of conduct set forth in the Delaware General Corporation Law, nor an actual determination by the Corporation (including the Board of Directors, its independent legal counsel or its stockholders) that the Officer has not met such applicable standard of conduct, shall be a defense to the action or create a presumption that the Officer has not met the applicable standard of conduct. 6. The Corporation shall maintain in full force and effect, at its own expense, Insurance coverage for the Officer in amounts and scope at least as favorable as that maintained by the Corporation on September 30, 1996, or, to the extent more favorable, any Insurance policy entered into or renewed by the Corporation following such date. Notwithstanding the foregoing, 3 if (a) the Corporation, after using its best efforts, cannot obtain and purchase such coverage for an amount no more than what it paid for the most recent expiring Insurance policy plus a reasonable additional amount and (b) the Corporation has so notified the Officer at the most recent address the Corporate Secretary has for the Officer, then the Corporation shall only be required to purchase such Insurance coverage for any act or omission occurring at or prior to the time of such notification or, if more favorable to the directors and officers of the Corporation as a whole, such Insurance coverage as is standard within the Corporation's industry. Such obligation shall continue for so long as the Officer may be subject to any possible claim which might be covered under such Insurance coverage. The Corporation agrees that money damages would not be a sufficient remedy for any breach of this provision and that the Officer shall be entitled to specific performance and injunctive or other equitable relief as remedies for any such breach. Such remedies shall not be deemed to be the exclusive remedies of the Officer, and shall be in addition to all other remedies available at law or in equity to the Officer. The Corporation waives any requirement for the securing or posting of any bond in connection with any such remedy. 7. The Officer shall give the Corporation and any insurance company providing Insurance coverage such information and cooperation in the defense of a Proceeding as they may reasonably require and as shall be within the Officer's power; provided, however, that if a Proceeding is brought by the Corporation, or if the Corporation is assisting or cooperating in the prosecution of a Proceeding against the Officer, the Officer shall only be required to provide information to and cooperate with any insurance company providing Insurance coverage. 8. The Officer shall give to the Corporation notice as soon practicable of any Proceeding for which indemnity will or could be sought under this Agreement, the Corporation's Bylaws or any other obligation whatsoever of the Corporation to indemnify the Officer or for which Insurance coverage could be available. 9. Nothing herein shall be deemed to diminish or otherwise restrict the Officer's right to indemnification under any provision of the Certificate of Incorporation or Bylaws of the Corporation, under Delaware law or under any other obligation whatsoever of the Corporation to indemnify the Officer. 10. In the event of payment under this Agreement, the Corporation shall be subrogated to the extent of such payment to all of the rights of recovery of the Officer, who shall execute all papers required and shall do everything that may be necessary to secure such rights, including the execution of such documents necessary to enable the Corporation effectively to bring suit to enforce such rights. 11. The provisions of this Agreement shall be severable in the event that any of the provisions hereof are held by a court of competent jurisdiction to be invalid, void or otherwise unenforceable, and the remaining provisions shall remain enforceable to the fullest extent permitted by law. Furthermore, to the fullest extent permitted, the provisions of this Agreement shall be construed so as to give effect to the intent manifested by any provision held invalid, void or otherwise unenforceable. 4 12. This Agreement shall be binding upon all successors and assigns of the Corporation (including any transferee of all or substantially all of its assets and any successor by merger, consolidation or operation of law) and shall inure to the benefit of the heirs, personal representatives and estate of the Officer. 13. This Agreement shall be governed by and construed in accordance with Delaware law. 14. The indemnification under this Agreement shall cover the Officer's service as an officer of the Corporation or as an Agent of an Affiliate and shall continue after he or she has ceased to act in such capacity with respect to all of his or her acts in such capacity, whether arising prior to, on or after the date of this Agreement. 15. No supplement, modification or amendment of this Agreement shall be binding unless executed in writing by the Corporation and the Officer. No waiver of any of the provisions of this Agreement shall operate as a waiver of any other provisions of this Agreement, nor shall any waiver constitute a continuing waiver. Except as specifically provided in this Agreement, no failure to exercise or delay in exercising any right or remedy under this Agreement shall constitute a waiver of the right or remedy. 16. This Agreement may be executed in any number of counterparts, all of which taken together shall constitute one instrument. IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be duly executed and signed as of the day and year first above written. UNOCAL CORPORATION OFFICER: By______________________________________ ______________________ ____________________, Vice President [Name of Officer] By______________________________________ ____________________, Secretary 5 EX-10 5 ex10-4.txt EX 10.4 (NEW) OFFICER INDEMNITY AGREEMENT Exhibit 10.4 UNOCAL CORPORATION OFFICER INDEMNITY AGREEMENT This Unocal Corporation Officer Indemnity Agreement ("Agreement") is made as of [date] by and between Unocal Corporation, a Delaware corporation (the "Corporation"), and [Name of Officer] (the "Officer") with reference to the following facts: RECITALS A. It is essential to the Corporation to retain and attract as officers the most capable persons available. B. It is now and has been the express policy of the Corporation to indemnify and insure its officers so as to provide them with the maximum possible protection permitted by law. C. The Officer is currently an officer of the Corporation and is performing valuable services for the Corporation. The Corporation wishes the Officer to continue in such capacity, and the Officer is willing, under certain circumstances, to continue in such capacity. D. The Bylaws of the Corporation provide for the indemnification of the officers of the Corporation to the maximum extent authorized by Section 145 of the Delaware General Corporation Law, as amended or as may be amended, revised or superseded. E. In addition to the indemnification to which the Officer is entitled pursuant to the Bylaws of the Corporation and as additional consideration for the Officer's services, the Corporation has, in the past, furnished at its expense director and officer liability insurance ("Insurance"). Many insurance carriers, as a condition of issuing Insurance policies, are requiring that corporations protect directors and officers from liability to the maximum extent permitted by law. F. The Officer has indicated that he or she does not regard the indemnities available under the Corporation's Bylaws and the Insurance currently in effect as adequate to protect him or her against the risks associated with his or her services to the Corporation. The Officer may not be willing to continue in office in the absence of the further lawful protection afforded by the instant Agreement. AGREEMENT NOW, THEREFORE, in order to induce the Officer to continue to serve as an officer of the Corporation and of certain subsidiaries and affiliates of the Corporation, in consideration for his or her continued services, and in order to do everything possible to procure and maintain adequate Insurance policies, the parties hereby agree as follows: 1. Subject only to the limitations set forth in Section 3, the Corporation will pay on behalf of the Officer and his or her heirs, executors, administrators or assigns any Expenses (as defined below) actually and reasonably incurred by the Officer because of any threatened, pending or completed action, suit, proceeding, inquiry, hearing or investigation, whether brought by or in the right of the Corporation or otherwise and whether of a civil, criminal, administrative or investigative nature (a "Proceeding"), resulting from any act or omission or neglect or breach of duty, including any actual or alleged error or misstatement or misleading statement, which he or she commits or suffers while acting in his or her capacity as an officer of the Corporation or, at the request of the Corporation, acting as a director, officer, trustee, fiduciary, employee, or agent (collectively, "Agent") of another foreign or domestic corporation, limited liability company, partnership, joint venture, trust, or any other enterprise or entity whatsoever, including without limitation, employee benefit plans (collectively, "Affiliate"), or by reason of the fact that the Officer is or was an officer of the Corporation or is or was serving at the request of the Corporation as an Agent of an Affiliate, whether the basis of such Proceeding is alleged action in an official capacity, or in any other capacity, to the fullest extent authorized by law, including but not limited to the Delaware General Corporation Law, as the same exists on the date hereof or as may hereafter be amended (but, in the case of any such amendment, only to the extent that such amendment permits the Corporation to provide broader indemnification rights than said law permitted the Corporation to provide prior to such amendment); provided, however, that except with respect to a Proceeding seeking to enforce rights to indemnification hereunder, the Corporation shall indemnify the Officer with respect to a Proceeding initiated by the Officer only if such Proceeding was authorized by the Board of Directors of the Corporation. 2. The payments (the "Expenses") which the Corporation will be obligated to make hereunder shall include any expense, liability or loss of the Officer, including without limitation, damages, judgments, fines, ERISA excise taxes, penalties, amounts paid or to be paid in settlement or in costs by or on behalf of the Officer, expenses relating to investigations or to judicial or administrative proceedings or appeals, attorneys' fees or any other costs of defense of legal actions, claims, or proceedings or appeals therefrom, costs of attachment or similar bonds, and any other amounts actually incurred or suffered by the Officer in connection with any Proceeding or in establishing a right of indemnification under this Agreement. The Corporation shall advance to the Officer as soon as practicable any Expenses incurred by the Officer upon receipt by the Corporation of an undertaking, if such undertaking is required by law, by or on behalf of the Officer to repay all amounts so advanced if the Officer is not entitled to be indemnified by the Corporation pursuant to this Agreement or otherwise, as decided by a court, arbitrator or other judicial agent having the requisite legal authority to make such a decision, which decision has become final and from which no appeal or other review proceeding is permissible. 3. The Corporation shall not be obligated under this Agreement to make any payment of Expenses to the Officer: (a) the payment of which is prohibited by Delaware law; (b) for which and to the extent payment is actually and unqualifiedly made to the Officer under an insurance policy or otherwise; or 2 (c) based upon or attributable to the Officer gaining in fact any personal profit or advantage to which he or she was not legally entitled, as decided by a court, arbitrator or other judicial agent having the requisite legal authority to make such a decision, which decision has become final and from which no appeal or other review proceeding is permissible. 4. If a claim under this Agreement is not paid by the Corporation, or on its behalf, within sixty (60) days after a written claim has been received by the Corporation (except in the case of a claim for the advancement of Expenses incurred in a Proceeding in advance of its final disposition, in which case the applicable period shall be twenty (20) days), the Officer may at any time thereafter bring suit against the Corporation to recover the unpaid amount of the claim, and if successful in whole or in part in such suit or in a suit brought by the Corporation to recover an advancement of Expenses pursuant to the terms of an undertaking, the Officer shall also be entitled to be paid the Expenses of prosecuting or defending such claim. The right to indemnification or advances as provided by this Agreement shall be enforceable by the Officer in any court of competent jurisdiction. The Corporation's sole defense to an action by the Officer seeking indemnification shall be that the Officer has not met the standard of conduct which makes it permissible under the Delaware General Corporation Law for the Corporation to indemnify the Officer for the amount claimed, and the burden of proving such defense shall be on the Corporation; provided, however, that in the case of a claim for the advancement of Expenses incurred in a Proceeding in advance of its final disposition where the required undertaking, if any is required, has been tendered to the Corporation, that defense shall not be available to the Corporation. Neither the failure of the Corporation (including the Board of Directors, its independent legal counsel or its stockholders) to have made a determination prior to the commencement of such action that indemnification of the Officer is proper under the circumstances because he or she has met the applicable standard of conduct set forth in the Delaware General Corporation Law, nor an actual determination by the Corporation (including the Board of Directors, its independent legal counsel or its stockholders) that the Officer has not met such applicable standard of conduct, shall be a defense to the action or create a presumption that the Officer has not met the applicable standard of conduct. 5. The Corporation shall maintain in full force and effect, at its own expense, Insurance coverage for the Officer in amounts and scope at least as favorable as that maintained by the Corporation on September 30, 1996, or, to the extent more favorable, any Insurance policy entered into or renewed by the Corporation following such date. Notwithstanding the foregoing, if (a) the Corporation, after using its best efforts, cannot obtain and purchase such coverage for an amount no more than what it paid for the most recent expiring Insurance policy plus a reasonable additional amount and (b) the Corporation has so notified the Officer at the most recent address the Corporate Secretary has for the Officer, then the Corporation shall only be required to purchase such Insurance coverage for any act or omission occurring at or prior to the time of such notification or, if more favorable to the directors and officers of the Corporation as a whole, such Insurance coverage as is standard within the Corporation's industry. Such obligation shall continue for so long as the Officer may be subject to any possible claim which might be covered under such Insurance coverage. The Corporation agrees that money damages would not be a sufficient remedy for any breach of this provision and that the Officer shall be entitled to specific performance and injunctive or other equitable relief as remedies for any such breach. 3 Such remedies shall not be deemed to be the exclusive remedies of the Officer, and shall be in addition to all other remedies available at law or in equity to the Officer. The Corporation waives any requirement for the securing or posting of any bond in connection with any such remedy. 6. The Officer shall give the Corporation and any insurance company providing Insurance coverage such information and cooperation in the defense of a Proceeding as they may reasonably require and as shall be within the Officer's power; provided, however, that if a Proceeding is brought by the Corporation, or if the Corporation is assisting or cooperating in the prosecution of a Proceeding against the Officer, the Officer shall only be required to provide information to and cooperate with any insurance company providing Insurance coverage. 7. The Officer shall give to the Corporation notice as soon practicable of any Proceeding for which indemnity will or could be sought under this Agreement, the Corporation's Bylaws or any other obligation whatsoever of the Corporation to indemnify the Officer or for which Insurance coverage could be available. 8. Nothing herein shall be deemed to diminish or otherwise restrict the Officer's right to indemnification under any provision of the Certificate of Incorporation or Bylaws of the Corporation, under Delaware law or under any other obligation whatsoever of the Corporation to indemnify the Officer. 9. In the event of payment under this Agreement, the Corporation shall be subrogated to the extent of such payment to all of the rights of recovery of the Officer, who shall execute all papers required and shall do everything that may be necessary to secure such rights, including the execution of such documents necessary to enable the Corporation effectively to bring suit to enforce such rights. 10. The provisions of this Agreement shall be severable in the event that any of the provisions hereof are held by a court of competent jurisdiction to be invalid, void or otherwise unenforceable, and the remaining provisions shall remain enforceable to the fullest extent permitted by law. Furthermore, to the fullest extent permitted, the provisions of this Agreement shall be construed so as to give effect to the intent manifested by any provision held invalid, void or otherwise unenforceable. 11. This Agreement shall be binding upon all successors and assigns of the Corporation (including any transferee of all or substantially all of its assets and any successor by merger, consolidation or operation of law) and shall inure to the benefit of the heirs, personal representatives and estate of the Officer. 12. This Agreement shall be governed by and construed in accordance with Delaware law. 13. The indemnification under this Agreement shall cover the Officer's service as an officer of the Corporation or as an Agent of an Affiliate and shall continue after he or she has 4 ceased to act in such capacity with respect to all of his or her acts in such capacity, whether arising prior to, on or after the date of this Agreement. 14. No supplement, modification or amendment of this Agreement shall be binding unless executed in writing by the Corporation and the Officer. No waiver of any of the provisions of this Agreement shall operate as a waiver of any other provisions of this Agreement, nor shall any waiver constitute a continuing waiver. Except as specifically provided in this Agreement, no failure to exercise or delay in exercising any right or remedy under this Agreement shall constitute a waiver of the right or remedy. 15. This Agreement may be executed in any number of counterparts, all of which taken together shall constitute one instrument. IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be duly executed and signed as of the day and year first above written. UNOCAL CORPORATION OFFICER: By___________________________ ______________________ Vice President [Name of Officer] By___________________________ Secretary EX-12 6 q12003_ex12-1.txt EX 12.1 UNOCAL RATIO EXHIBIT 12.1
UNOCAL CORPORATION AND CONSOLIDATED SUBSIDIARIES COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES For the Three Months Ended March 31, ------------------------------- Millions of dollars 2003 2002 - ------------------------------------------------------------------------------------------------------------------ Earnings from continuing operations $ 217 $ 22 Provision for income taxes 168 40 Minority Interests 2 1 Distributions greater than earnings from equity investments (11) 18 - ------------------------------------------------------------------------------------------------------------------ Earnings subtotal (a) 376 81 Fixed charges included in earnings: Interest expense 38 51 Distribution on convertible preferred securities 8 8 Interest portion of rentals (b) 6 5 - ------------------------------------------------------------------------------------------------------------------ Fixed charges subtotal 52 64 Earnings from continuing operations available before fixed charges $ 428 $ 145 ================================================================================================================== Fixed charges: Fixed charges included in earnings $ 52 $ 64 Capitalized interest 16 9 - ------------------------------------------------------------------------------------------------------------------ Total fixed charges $ 68 $ 73 - ------------------------------------------------------------------------------------------------------------------ Ratio of earnings from operations to fixed charges 6.3 2.0 - ------------------------------------------------------------------------------------------------------------------ (a) Includes pre-tax Impairment of: - - The ratio of earnings, excluding impairment, to fixed charges would be: 6.3 2.0 (b) Calculated as one-third of operating rental expense.
EX-12 7 q12003_ex12-2.txt EXH 12.2 UNION OIL RATIO EXHIBIT 12.2
UNION OIL COMPANY OF CALIFORNIA AND CONSOLIDATED SUBSIDIARIES COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES For the Three Months Ended March 31, ------------------------------- Millions of dollars 2003 2002 - ------------------------------------------------------------------------------------------------------------------ Earnings from continuing operations $ 225 $ 30 Provision for income taxes 170 43 Minority Interests 2 1 Distributions greater than earnings from equity investments (11) 18 - ------------------------------------------------------------------------------------------------------------------ Earnings subtotal 386 92 Fixed charges included in earnings: Interest expense 38 51 Interest portion of rentals 6 5 - ------------------------------------------------------------------------------------------------------------------ Fixed charges subtotal 44 56 Earnings from continuing operations available before fixed charges $ 430 $ 148 ================================================================================================================== Fixed charges: Fixed charges included in earnings $ 44 $ 56 Capitalized interest 16 9 - ------------------------------------------------------------------------------------------------------------------ Total fixed charges $ 60 $ 65 - ------------------------------------------------------------------------------------------------------------------ Ratio of earnings from operations to fixed charges 7.2 2.3 - ------------------------------------------------------------------------------------------------------------------ (a) Includes pre-tax Impairment of: - - The ratio of earnings, excluding impairment, to fixed charges would be: 7.2 2.3 (b) Calculated as one-third of operating rental expense.
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