10-Q 1 q32002_10q.txt UNOCAL'S 3RD QUARTER 10-Q UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D. C. 20549 FORM 10-Q (Mark One) [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended September 30, 2002 -------------------- 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 ------- ------- Number of shares of Common Stock, $1 par value, outstanding as of October 31, 2002: 257,896,541 TABLE OF CONTENTS PAGE Glossary.................................................................... ii PART I 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....................... 29 Operating Highlights ............................................... 33 Item 3. Quantative and Qualitative Disclosures About Market Risk............ 45 Item 4. Controls and Procedures............................................. 50 PART II Item 1. Legal Proceedings................................................... 50 Item 6. Exhibits and Reports on Form 8-K.................................... 51 SIGNATURE................................................................... 52 CERTIFICATIONS.............................................................. 53 EXHIBIT INDEX............................................................... 55 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 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 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). 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 believed to be 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. ii 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 it can be cooled or subjected to pressure to facilitate storage and transportation. o Multilateral institution refers to an institution with shareholders from multiple countries that lends money for specific development reasons. Examples of multilateral institutions are International Finance Corporation ("IFC"), European Bank for Reconstruction and Development ("EBRD"), and Asian Development Bank ("ADB"). o Natural Gas Liquids ("NGLs") are primarily ethane, propane, butane and natural gasolines which can be extracted from wet natural gas and become liquid under various combinations of increasing pressure and lower temperature. o Net acreage and net oil and gas wells are obtained by multiplying gross acreage and gross oil and gas wells by the Company's working interest percentage in the properties. o Net pay is the amount of oil or gas saturated rock capable of producing oil or gas. o Production Sharing Contract ("PSC") is a contractual agreement between the Company and a host government whereby the Company, acting as contractor, bears all exploration costs, development and production costs in return for an agreed upon share of the proceeds from the sale of production. o Producible well is a well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes. o Prospective acreage is lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas. o Proved acreage is acreage that is allocated to producing wells or wells capable of production or to acreage that is being developed. o Reservoir is a porous and permeable underground formation containing oil and/or natural gas enclosed or surrounded by layers of less permeable rock and is individual and separate from other reservoirs. o Subsea tieback is a well with the wellhead equipment located on the bottom of the ocean. o Take-or-Pay is a type of contract clause where specific quantities of a product must be paid for, even if delivery is not taken. Normally, the purchaser has the right in following years to take product that had been paid for but not taken. o Trend or Play is an area or region of concentrated activity with a group of related fields and prospects. o Working interest is the percentage of ownership that the Company has in a joint venture, partnership, consortium, project or acreage. ii PART I - FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS
CONSOLIDATED EARNINGS (UNAUDITED) UNOCAL CORPORATION For the Three Months For the Nine Months Ended September 30, Ended September 30, ------------------------------------------------------ Millions of dollars except per share amounts 2002 2001 2002 2001 ------------------------------------------------------------------------------------------------------------------------------ Revenues Sales and operating revenues $ 1,287 $ 1,573 $ 3,660 $ 5,463 Interest, dividends and miscellaneous income (loss) (3) 8 17 27 Gain (loss) on sales of assets 1 (2) 2 (1) ------------------------------------------------------------------------------------------------------------------------------ Total revenues 1,285 1,579 3,679 5,489 Costs and other deductions Crude oil, natural gas and product purchases 401 617 1,124 2,141 Operating expense 314 352 914 1,011 Administrative and general expense 34 25 114 96 Depreciation, depletion and amortization 245 246 724 714 Impairments 6 - 27 - Dry hole costs 40 53 81 140 Exploration expense 60 61 180 172 Interest expense 40 48 134 145 Property and other operating taxes 7 19 41 60 Distributions on convertible preferred securities of subsidiary trust 8 8 24 24 ------------------------------------------------------------------------------------------------------------------------------ Total costs and other deductions 1,155 1,429 3,363 4,503 Earnings from equity investments 35 37 123 128 ------------------------------------------------------------------------------------------------------------------------------ Earnings from continuing operations before income taxes and minority interests 165 187 439 1,114 ------------------------------------------------------------------------------------------------------------------------------ Income taxes 68 77 203 447 Minority interests (2) 8 2 38 ------------------------------------------------------------------------------------------------------------------------------ Earnings from continuing operations 99 102 234 629 Discontinued operations Refining, marketing and transportation Gain on disposal (net of tax) - - 1 16 ------------------------------------------------------------------------------------------------------------------------------ Earnings from discontinued operations - - 1 16 Cumulative effect of accounting change - - - (1) ------------------------------------------------------------------------------------------------------------------------------ Net earnings $ 99 $ 102 $ 235 $ 644 ============================================================================================================================== Basic earnings per share of common stock (a) Continuing operations $ 0.41 $ 0.42 $ 0.96 $ 2.59 Net earnings $ 0.41 $ 0.42 $ 0.96 $ 2.65 Diluted earnings per share of common stock (b) Continuing operations $ 0.41 $ 0.42 $ 0.96 $ 2.53 Net earnings $ 0.41 $ 0.42 $ 0.96 $ 2.59 Cash dividends declared per share of common stock $ 0.20 $ 0.20 $ 0.60 $ 0.60 ------------------------------------------------------------------------------------------------------------------------------ (a) Basic weighted average shares outstanding (in thousands) 244,664 243,601 244,503 243,426 (b) Diluted weighted average shares outstanding (in thousands) 245,226 244,566 245,378 256,812 See Notes to the Consolidated Financial Statements.
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CONSOLIDATED BALANCE SHEET UNOCAL CORPORATION At September 30, At December 31, ------------------------------------------ Millions of dollars 2002 (a) 2001 ------------------------------------------------------------------------------------------------------------------- Assets Current assets Cash and cash equivalents $ 275 $ 190 Accounts and notes receivable - net 690 847 Inventories 103 102 Deferred income taxes 97 123 Other current assets 20 33 ------------------------------------------------------------------------------------------------------------------- Total current assets 1,185 1,295 Investments and long-term receivables - net 1,549 1,405 Properties - net (b) 7,784 7,514 Deferred income taxes 179 128 Other assets 103 83 ------------------------------------------------------------------------------------------------------------------- Total assets $ 10,800 $ 10,425 =================================================================================================================== Liabilities and Stockholders' Equity Current liabilities Accounts payable $ 873 $ 823 Taxes payable 175 249 Dividends payable 49 49 Interest payable 46 49 Current portion of environmental liabilities 126 124 Current portion of long-term debt and capital leases 8 9 Other current liabilities 181 119 ------------------------------------------------------------------------------------------------------------------- Total current liabilities 1,458 1,422 Long-term debt and capital leases 3,070 2,897 Deferred income taxes 731 627 Accrued abandonment, restoration and environmental liabilities 595 590 Other deferred credits and liabilities 706 724 Subsidiary stock subject to repurchase 111 70 Minority interests 425 449 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)) 255 255 Capital in excess of par value 573 551 Unearned portion of restricted stock issued (23) (29) Retained earnings 2,977 2,888 Accumulated other comprehensive income (147) (88) Notes receivable - key employees (42) (42) Treasury stock - at cost (d) (411) (411) ------------------------------------------------------------------------------------------------------------------- Total stockholders' equity 3,182 3,124 ------------------------------------------------------------------------------------------------------------------- Total liabilities and stockholders' equity $ 10,800 $ 10,425 =================================================================================================================== (a) Unaudited (b) Net of accumulated depreciation, depletion and amortization of: $ 12,149 $ 11,648 (c) Number of shares outstanding (in thousands) 244,661 243,998 (d) Number of shares (in thousands) 10,623 10,623 See Notes to the Consolidated Financial Statements.
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CONSOLIDATED CASH FLOWS (UNAUDITED) UNOCAL CORPORATION For the Nine Months Ended September 30, --------------------------------- Millions of dollars 2002 2001 -------------------------------------------------------------------------------------------------------------------------- Cash Flows from Operating Activities Net earnings $ 235 $ 644 Adjustments to reconcile net earnings to net cash provided by operating activities Depreciation, depletion and amortization 724 714 Impairments 27 - Dry hole costs 81 140 Amortization of exploratory leasehold costs 74 69 Deferred income taxes 25 113 (Gain) loss on sales of assets (pre-tax) (2) 1 (Gain) on disposal of discontinued operations (pre-tax) (2) (25) Earnings applicable to minority interests 2 38 Other (56) 115 Working capital and other changes related to operations Accounts and notes receivable 160 360 Inventories (2) (4) Accounts payable 44 (194) Taxes payable 4 (24) Other (82) (167) -------------------------------------------------------------------------------------------------------------------------- Net cash provided by operating activities 1,232 1,780 -------------------------------------------------------------------------------------------------------------------------- Cash Flows from Investing Activities Capital expenditures (includes dry hole costs) (1,248) (1,257) Major acquisitions - (536) Proceeds from sales of assets 61 26 Proceeds from sale of discontinued operations 3 25 -------------------------------------------------------------------------------------------------------------------------- Net cash used in investing activities (1,184) (1,742) -------------------------------------------------------------------------------------------------------------------------- Cash Flows from Financing Activities Long-term borrowings 437 467 Reduction of long-term debt and capital lease obligations (267) (221) Minority interests (6) (17) Proceeds from issuance of common stock 19 14 Dividends paid on common stock (147) (146) Other 1 1 -------------------------------------------------------------------------------------------------------------------------- Net cash provided by financing activities 37 98 -------------------------------------------------------------------------------------------------------------------------- Net increase in cash and cash equivalents 85 136 -------------------------------------------------------------------------------------------------------------------------- Cash and cash equivalents at beginning of year 190 235 -------------------------------------------------------------------------------------------------------------------------- Cash and cash equivalents at end of period $ 275 $ 371 ========================================================================================================================== Supplemental disclosure of cash flow information: Cash paid during the period for: Interest (net of amount capitalized) $ 136 $ 150 Income taxes (net of refunds) $ 211 $ 354 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 amended 2001 Annual Report on Form 10-K/A. For the purpose of this report, Unocal Corporation ("Unocal") and its consolidated subsidiaries, including Union Oil Company of California ("Union Oil"), are referred to as the "Company". The consolidated financial statements of the Company include the accounts of subsidiaries in which a controlling interest is held. Investments in entities without a controlling interest are accounted for by the equity method or cost basis. Under the equity method, the investments are stated at cost plus the Company's equity in undistributed earnings and losses after acquisition. Income taxes estimated to be payable when earnings are distributed are included in deferred income taxes. Results for the nine months ended September 30, 2002, are not necessarily indicative of future financial results. Certain items in the prior year financial statements have been reclassified to conform to the 2002 presentation. 2. Accounting Changes Effective January 1, 2002, the Company adopted Statement of Financial Accounting Standards ("SFAS") No. 142, "Goodwill and Other Intangible Assets". SFAS No. 142 addresses accounting for goodwill and identifiable intangible assets subsequent to their initial recognition, eliminates the amortization of goodwill and provides specific steps for testing the impairment of goodwill. Separable intangible assets that are not deemed to have an indefinite life will continue to be amortized over their useful lives. SFAS No. 142 also eliminates amortization of the excess of cost over the underlying equity in the net assets of an equity method investee that is recognized as goodwill. The adoption of the statement did not have a material effect on the Company's financial position and results of operations. Effective January 1, 2002, the Company also adopted SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets", which addresses financial accounting and reporting for the impairment or disposal of long-lived assets. SFAS No. 144 supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of", and the accounting and reporting provisions of Accounting Principles Board Opinion No. 30, "Reporting the Results of Operations--Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions". The adoption of SFAS No. 144 did not have a material effect on the Company's financial position and results of operations. The Company has adopted SFAS No. 145, "Rescission of SFAS No. 4, 44, and 64, Amendment of SFAS No. 13, and Technical Corrections." This statement rescinds SFAS No. 4, "Reporting Gains and Losses from Extinguishment of Debt", and an amendment of that statement, SFAS No. 64, "Extinguishments of Debt Made to Satisfy Sinking-Fund Requirements". This statement also rescinds or amends other existing authoritative pronouncements to make various technical corrections, clarify meanings, or describe their applicability under changed conditions. The adoption of SFAS No. 145 did not have a material effect on the Company's financial position and results of operations. -4- In June 2002, the FASB issued 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 and is effective for the Company on January 1, 2003. The Company does not expect the adoption of SFAS No. 146 to have a significant impact on its financial position and results of operations. In August 2001, the FASB issued SFAS No 143, "Accounting for Asset Retirement Obligations". It is effective for fiscal years beginning after June 15, 2002, and it requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred, as a capitalized cost of the long-lived asset and to depreciate it over the useful life of the asset. The Company is currently in the process of evaluating the impact that SFAS No. 143 will have on its financial position and results of operations. 3. Other Financial Information During the third quarters of 2002 and 2001, approximately 24 percent and 32 percent, respectively, of total sales and operating revenues were attributable to the resale of liquids and natural gas purchased from others in connection with marketing activities. For the nine months ended September 30, 2002 and 2001, these percentages were approximately 23 percent and 32 percent, respectively. Related purchase costs are classified as expense in the crude oil, natural gas and product purchase category on the consolidated earnings statement. The current year percentage decreases were principally due to lower purchases of domestic crude oil from third parties for resale, reflecting management's continued efforts to decrease its outside crude oil purchases for resale due to increased volatility in the oil markets. Capitalized interest totaled $14 million and $8 million for the third quarters of 2002 and 2001, respectively, and $33 million and $19 million for the nine months ended September 30, 2002 and 2001, respectively. The increase was primarily due to the capitalized interest related to the West Seno oil and gas development project in the deepwater Kutei Basin, offshore East Kalimantan, Indonesia, and the Mad Dog oil development project in the deepwater Gulf of Mexico. Exploration expense on the consolidated earnings statement consisted of the following:
For the Three Months For the Nine Months Ended September 30, Ended September 30, ------------------------------------------ Millions of dollars 2002 2001 2002 2001 -------------------------------------------------------------------------------- Exploration operations $ 18 $ 22 $ 66 $ 62 Geological and geophysical 10 11 29 30 Amortization of exploratory leases 29 24 74 69 Leasehold rentals 3 4 11 11 -------------------------------------------------------------------------------- Exploration expense $ 60 $ 61 $ 180 $ 172 ================================================================================
4. Restructuring In June 2002, the Company 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 approximately 200 employees in the Company's Sugar Land, Texas, office and field locations. The restructuring plan involves organizational changes to eliminate unnecessary work processes in the Company's Gulf Region business unit, which is part of the U.S. Lower 48 operations in the Exploration and Production segment. The restructuring charge was reflected in the operating expense line on the consolidated earnings statement and included approximately $14 million for termination costs to be paid to the employees over time, about $3 million for outplacement and other costs and about $2 million for benefit plan curtailment costs. All of the affected employees had been terminated as of September 30, 2002. -5- 5. Impairments The Company, as part of its regular assessment, reviewed its developed and undeveloped oil and gas properties and other long-lived assets for possible impairment. In the third quarter of 2002, the Company recorded a pre-tax charge of $6 million, or $4 million after-tax, primarily due to impairment related to a U.S. pipeline company, in which the Company owns an equity interest. The Company's equity interests in petroleum pipeline companies are part of the Midstream segment. In the nine months period of 2002, the Company recorded a pre-tax charge of $27 million, or $17 million after-tax, for the impairment of oil and gas fields in Alaska and the Gulf of Mexico region and the aforementioned pipeline company impairment. The impairment in Alaska was $19 million pre-tax, or $12 million after-tax. 6. Income Taxes Income taxes on earnings from continuing operations for the third quarter and nine months periods of 2002 were $68 million and $203 million, respectively, compared with $77 million and $447 million for the comparable periods of 2001. The effective income tax rates for the third quarter and nine months periods of 2002 were 41 percent and 46 percent, respectively, compared with 41 percent and 40 percent for the comparable periods of 2001. The higher effective income tax rate for the nine months period of 2002, as compared with the same period a year ago, reflected the effect of changes in the mix of domestic losses in 2002 and earnings in 2001 coupled with foreign earnings in both years, which are generally taxed at higher rates, along with foreign currency effects, primarily in Thailand. In 2002, the Company anticipates electing to carryback a current year domestic source net operating loss for a refund of prior year federal income tax paid. 7. Earnings Per Share The following are reconciliations of the numerators and denominators of the basic and diluted earnings per share ("EPS") computations for earnings from continuing operations for the third quarters and nine months ended September 30, 2002 and 2001:
Earnings Shares Per Share Millions except per share amounts (Numerator) (Denominator) Amount --------------------------------------------------------------------------------------------------------------------------- Three months ended September 30, 2002 Earnings from continuing operations $ 99 244.6 Basic EPS $ 0.41 ============= Effect of dilutive securities Options and common stock equivalents 0.6 -------------------------------- Diluted EPS 99 245.2 $ 0.41 ============= Distributions on subsidiary trust preferred securities (after-tax) 7 12.3 -------------------------------- Antidilutive $ 106 257.5 $ 0.41 Three months ended September 30, 2001 Earnings from continuing operations $ 102 243.6 Basic EPS $ 0.42 ============= Effect of dilutive securities Options and common stock equivalents 1.0 -------------------------------- Diluted EPS 102 244.6 $ 0.42 ============= Distributions on subsidiary trust preferred securities (after-tax) 7 12.3 -------------------------------- Antidilutive $ 109 256.9 $ 0.42 ---------------------------------------------------------------------------------------------------------------------------
-6- Not included in the computation of diluted EPS for the three months ended September 30, 2002 and 2001, were options outstanding to purchase approximately 8 million and 5.2 million shares, respectively, of common stock. These options were not included in the computation as the exercise prices were greater than average market prices of the common shares during the respective quarters.
Earnings Shares Per Share Millions except per share amounts (Numerator) (Denominator) Amount --------------------------------------------------------------------------------------------------------------------------- Nine months ended September 30, 2002 Earnings from continuing operations $ 234 244.5 Basic EPS $ 0.96 ============= Effect of dilutive securities Options and common stock equivalents 0.9 -------------------------------- Diluted EPS 234 245.4 $ 0.96 ============= Distributions on subsidiary trust preferred securities (after-tax) 20 12.3 -------------------------------- Antidilutive $ 254 257.7 $ 0.99 Nine months ended September 30, 2001 Earnings from continuing operations $ 629 243.4 Basic EPS $ 2.59 ============= Effect of dilutive securities Options and common stock equivalents 1.1 -------------------------------- 629 244.5 $ 2.57 Distributions on subsidiary trust preferred securities (after-tax) 20 12.3 -------------------------------- Diluted EPS $ 649 256.8 $ 2.53 ============= ---------------------------------------------------------------------------------------------------------------------------
The diluted EPS computation for the nine months ended September 30, 2002 and 2001, did not include options outstanding to purchase approximately 5.8 million and 6.3 million shares, respectively, of common stock. These options were not included in the computation as the exercise prices were greater than the year-to-date average market price of the common shares. Basic and diluted earnings per common share for discontinued operations were as follows:
For the Three Months For the Nine Months Ended September 30, Ended September 30, ------------------------------------------------------- Millions except per share amounts 2002 2001 2002 2001 ---------------------------------------------------------------------------------------------------------------------- Basic earnings per share of common stock: Discontinued operations: Earnings from discontinued operations $ - $ - $ 1 $ 16 Weighted average common shares outstanding 244.6 243.6 244.5 243.4 Earnings from discontinued operations $ - $ - $ - $ 0.06 Dilutive earnings per share of common stock: Discontinued operations: Earnings from discontinued operations $ - $ - $ 1 $ 16 Weighted average common shares outstanding 245.2 244.6 245.4 256.8 Earnings from discontinued operations $ - $ - $ - $ 0.06
-7- 8. Comprehensive Income The Company's comprehensive income was:
For the Three Months For the Nine Months Ended September 30, Ended September 30, --------------------------------------------------- Millions of dollars 2002 2001 2002 2001 -------------------------------------------------------------------------------------------------------------------------- Net earnings $ 99 $ 102 $ 235 $ 644 Cumulative effect of change in accounting principle SFAS No. 133 adoption (a) - - - (59) Change in unrealized loss on hedging instruments (b) (26) 17 (35) 43 Reclassification adjustment for settled hedging contracts (c) - (3) (1) 23 Unrealized foreign currency translation adjustments (55) (24) (23) (40) -------------------------------------------------------------------------------------------------------------------------- Total comprehensive income $ 18 $ 92 $ 176 $ 611 ========================================================================================================================== (a) Net of tax expense (benefit) of: - - - (36) (b) Net of tax expense (benefit) of: (15) 10 (21) 25 (c) Net of tax expense (benefit) of: - (2) - 14
9. Cash and Cash Equivalents
At September 30, At December 31, ---------------------------------------- Millions of dollars 2002 2001 ------------------------------------------------------------------------------- Cash $ 9 $ 12 Time deposits 167 123 Restricted cash 4 5 Marketable securities 95 50 ------------------------------------------------------------------------------- Cash and cash equivalents $ 275 $ 190 ===============================================================================
10. Long Term Debt and Credit Agreements During the nine months period of 2002, the Company's consolidated debt, including the current portion, increased by $173 million. This net increase included $437 million in new commercial paper borrowings, the proceeds of which were used to refinance maturing debt and for general corporate purposes. The commercial paper had a weighted average interest rate of 2.74 percent at September 30, 2002. The Company retired $152 million of maturing medium-term notes during the nine months period of 2002. In February 2002, the Company's Northrock Resources Ltd. subsidiary redeemed its $35 million "Series A" and $40 million "Series B" senior U.S. dollar-denominated notes, which bore interest of 6.54 percent and 6.74 percent, respectively. The Company's Pure Resources, Inc. ("Pure") subsidiary reduced its long-term debt, included in the Company's consolidated debt, by $34 million principally due to a decrease in borrowing under its revolving credit facilities. Pure's debt was $553 million at September 30, 2002. Neither Unocal nor Union Oil guarantees any of Pure's debt. 11. Accrued Abandonment, Restoration and Environmental Liabilities At September 30, 2002, the Company had accrued $479 million for the estimated future costs to abandon and remove wells and production facilities. At December 31, 2001, the Company had accrued $477 million. The total costs for these abandonments are predominantly accrued on a unit-of-production basis and were estimated to be approximately $725 million and $670 million at September 30, 2002 and December 31, 2001, respectively. This estimate was derived in large part from abandonment cost studies performed by independent third party firms and is used to calculate the amount to be amortized. The Company's reserves for environmental remediation obligations at September 30, 2002 totaled $242 million, of which $126 million were included in current liabilities. This compared with $237 million at December 31, 2001, of which $124 million were included in current liabilities. -8- 12. 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 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 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 11, at September 30, 2002, the Company had accrued $242 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 $245 million. The amount of such possible additional costs reflects the aggregate of the high ends of the ranges of costs of feasible alternatives identified by the Company for those sites with respect to which investigation or feasibility studies have advanced to the stage of analyzing such alternatives. However, such estimated possible additional costs are not an estimate of the total remediation costs beyond the amounts reserved, because there are sites where the Company is not yet in a position to estimate all, or in some cases any, possible additional costs. Both the amounts reserved and estimates of possible additional costs may change in the near term, and in some cases could change substantially, as additional information becomes available regarding the nature and extent of site contamination, required or agreed-upon remediation methods and other actions by government agencies and private parties. -9- The accrued costs and the possible additional costs are shown below for four categories of sites:
At September 30, 2002 ---------------------------- Possible Millions of dollars Reserves Additional -------------------------------------------------------------------------------- Superfund and similar sites $ 18 $ 11 Active Company facilities 38 63 Company facilities sold with retained liabilities and former Company-operated sites 90 69 Inactive or closed Company facilities 96 102 -------------------------------------------------------------------------------- Total reserves $ 242 $ 245 ================================================================================
The time frames over which the amounts included in the reserves 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 reserves will be made in different 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 reserves. 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 reserves 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 reserves reflect the Company's estimated shares of those costs. In the case of many of the oil and gas sites, remediation cost sharing is provided for 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 agreements. 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 contaminated waste 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 or impoundments that were used in these operations. Also, included in these categories are former oil and gas fields that the Company no longer operates. In most cases, these sites are contaminated with crude oil, oil field waste and other petroleum hydrocarbons. Contamination at other sites in this category was the result of former industrial chemical and polymers manufacturing and distribution facilities, agricultural chemical retail businesses and ferromolybdenum production operations. -10- Superfund and similar sites - At September 30, 2002, Unocal had received notifications from the U.S. Environmental Protection Agency ("EPA") that the Company may be a PRP at 29 sites and may share certain liabilities at these sites. Of the total, three sites are under investigation and/or litigation and the Company's potential liability is not presently determinable and for one site the Company has denied responsibility. At one site, the Company has made a final settlement payment and is in the process of completing its involvement in the site. Of the remaining 24 sites, where the Company has concluded that liability is probable and to the extent costs can be reasonably estimated, reserves of $12 million have been established for future remediation and settlement costs. Various state agencies and private parties had identified 22 other similar PRP sites. Three sites are under investigation and/or litigation and the Company's potential liability is not presently determinable and for two sites, the Company has denied responsibility. At three sites the Company's potential liability appears to be de minimis. At another site, the Company has made final settlement payments and is in the process of completing its involvement in the site. Where the Company has concluded that liability is probable and to the extent costs can be reasonably estimated at the remaining 13 sites, reserves of $6 million have been established for future remediation and settlement costs. In addition to the total of $18 million in reserves mentioned above, the Company has also estimated that additional costs of $11 million are possible for the "Superfund and similar sites" category. 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 These 51 sites exclude 110 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 - The Company has established reserves of $38 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. 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 estimates that it may incur possible additional costs of $63 million for this category of sites. 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. -11- In each sale, the Company retained a contractual remediation or indemnification obligation and is responsible only for certain environmental problems associated with its past operations. The reserves represent 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 established aggregate reserves of $90 million and additional costs of $69 million are possible for this category. The possible additional costs are primarily related to service station and distribution facilities and oil and gas properties. Inactive or closed Company facilities - Reserves of $96 million have been established for these types of 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. The sites in this category also have possible additional costs of $102 million associated with them. 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 Beaumont, Texas, facility, a former agricultural chemical facility in Corcoran, California, and Molycorp's Washington, Pennsylvania, facility. 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 September 30, 2002, amounts included in the remediation reserves for these facilities totaled $103 million. 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 $74 million. Although any possible additional costs 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 reserves recorded on the consolidated balance sheet represent the Company's estimates of assessment and remediation costs based on currently available facts, existing technology and presently enacted laws and regulations. The remediation cost estimates, in many cases, are based on plans recommended to the regulatory agencies for approval and are subject to future revisions. The ultimate costs to be incurred could exceed the total amounts reserved. The reserve will be adjusted as additional information becomes available regarding the nature and extent of site contamination, required or agreed-upon remediation methods and other actions by government agencies and private parties. Therefore, amounts reserved may change substantially in the near term. -12- 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 due either 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 September 2000, the City of Santa Monica (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 of water pumped from its Charnock wellfield (City of Santa Monica v Shell Oil Company et al, California Superior Court, Orange County, Case No. 01CC04331). In August 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. The City's first amended complaint, filed in May 2002, alleges causes of action for strict liability (gasoline containing MTBE as a defective product designed, manufactured and sold without adequate warnings), negligence, trespass, public and private nuisance, declaratory relief and unfair competition. The City seeks damages, a declaration that the defendants are liable for all remedial actions, abatement of nuisance and injunctive relief. The City alleges that releases from sites of units of Shell, ChevronTexaco Corporation and ExxonMobil Corporation were the releases which caused the wellfield to be shut down. Releases from Company sites allegedly impacted the wellfield subsequently. The Company filed its answer to the City's complaint in August 2002. In November 2002, the City, ChevronTexaco and ExxonMobil entered into a settlement, subject to court approval, under which the two companies would pay the City $30 million and construct and operate a water treatment plant. Future settlement and/or judgment amounts paid to the City from other defendants would go in part into an operating account, from which the two companies could be reimbursed for part or all of their treatment plant costs, as well as certain other costs. The Company, Tosco Corporation (now a unit of Phillips Petroleum Company) and other defendants, but not the Shell defendants, have been invited to participate in this settlement. The Company is evaluating its position with regard to participation, which would involve its paying the City $7.5 million and contributing to the costs of the treatment plant. However, 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 liabilities arising from its former gasoline marketing business that was sold in 1997. The Company's current analysis does not indicate any such liabilities are likely to be significant. 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. The impact of the proposed settlement in the City's lawsuit on future government agency actions is uncertain. 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. -13- Agrium Litigation: In June 2002, a lawsuit was filed against the Company by Agrium Inc., a Canadian corporation, and a U. S. subsidiary in the California Superior Court, Los Angeles County (Agrium U.S. Inc. and Agrium Inc. v. Union Oil Company of California, Case No. BC275407). The Company subsequently removed the case to the U.S. District Court for the Central District of California (Case No. 02-04769 Nm). The Agrium entities ("Agrium") allege numerous causes of action relating to their 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 a Gas Purchase and Sale Agreement (the "GPSA") between the parties. Agrium alleges that the Company misrepresented the amount of gas reserves available for sale to the plant as of the closing of the transaction and that the Company has failed to develop additional 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. Also in June 2002, the Company filed a lawsuit against Agrium in the U.S. District Court for the Central District of California (Union Oil Company of California v. Agrium Inc. and Agrium U.S. Inc., Case No. 02-04518 Nm(Ctx)). 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 $16.6 million, together with interest accrued subsequent to May 31, 2002. The Company believes that certain portions of its disputes with Agrium are subject to binding arbitration under the terms of the GPSA, and has initiated arbitration respecting the gas supply available under that agreement. Agrium claims the dispute resolution provisions of the agreement for the sale of the plant (the "PSA") supersede the arbitration provisions of the GPSA. Agrium has filed motions to stay the Company's lawsuit, to enjoin implementation of the arbitration and for Agrium's lawsuit to be remanded to the state court. A hearing on these motions is set for December 2002. The federal court denied a motion by Agrium to temporarily restrain implementation of the arbitration. 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 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. In September 2002, Agrium amended its complaint to add allegations that Unocal breached certain conditions of the September 2000 closing, breached certain indemnification obligations, and violated the pertinent health and safety code. Agrium also asked for rescission of the sale of the fertilizer plant, in addition, or as an alternative, to money damages. Petrobangla Claim: In July 2002, the Company's subsidiary Unocal Bangladesh Blocks Thirteen and Fourteen, Ltd. (which was acquired in 1999 from Occidental Petroleum Corporation and, prior to the recent completion of Bangladesh name-change formalities, was still known in Bangladesh as Occidental of Bangladesh Ltd.) ("OBL"), received from the Bangladesh Oil, Gas & Mineral Corporation ("Petrobangla") a letter 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 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. -14- 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 OBL has advised Petrobangla that no additional compensation is warranted. 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 three preceding matters will be. However, based on current knowledge, none of the preceding matters is presently expected to have a material adverse effect on the Company's consolidated financial condition or liquidity, but each of them could have a material adverse effect on the Company's results of operations for the accounting period or periods in which one or more of them might be resolved adversely. Tax matters The Company believes it has adequately provided in its accounts for tax items and issues not yet resolved. Several prior material tax issues are unresolved. Resolution of these tax issues impact not only the year in which the items arose, but also the Company's tax situation in other tax years. With respect to 1979-1984 taxable years, all issues raised for these years have now been settled, with the exception of the effect of the carryback of a 1993 net operating loss ("NOL") to tax year 1984 and resultant credit adjustments. The 1985-1990 taxable years are before the Appeals division of the Internal Revenue Service. All issues raised with respect to those years have now been settled, with the exception of the effect of the 1993 NOL carryback and resultant adjustments. The Joint Committee on Taxation of the U.S. Congress has reviewed the settled issues with respect to 1979-1990 taxable years and no additional issues have been raised. While all tax issues for the 1979-1990 taxable years have been agreed and reviewed by the Joint Committee, these taxable years will remain open due to the 1993 NOL carryback. The 1993 NOL results from certain specified liability losses, which occurred during 1993, and which resulted in a tax refund of $73 million. Consequently, these tax years will remain open until the specified liability loss, which gave rise to the 1993 NOL, is finally determined by the Internal Revenue Service and is either agreed to with the IRS or otherwise concluded in the Tax Court proceeding. In 1999, the United States Tax Court granted Unocal's motion to amend the pleadings in its Tax Court cases to place the 1993 NOL carryback in issue. The 1991-1994 taxable years are now before the Appeals division of the Internal Revenue Service. The 1995-1997 taxable years are under examination by the Internal Revenue Service. Pure Resources, Inc. Employment and Severance Agreements Under circumstances specified in the employment and/or severance agreements entered into between the Company's Pure subsidiary and its officers, each covered officer will have the right to require Pure to purchase its common shares currently held or subsequently obtained by the exercise of any option held by the officer at a calculated "net asset value" per share. The circumstances under which certain officers may exercise this right include the termination of the officer without cause prior to May 25, 2003, termination for any reason after May 24, 2003, a change in control of either Pure or Unocal and other events specified in the agreements. The net asset value per share is calculated by reference to each common share's pro rata amount of the present value of Pure's proved reserves discounted at 10 percent, as defined, times 110 percent, less funded debt, as defined. At September 30, 2002, Pure estimated that the amount it may have to repurchase under these agreements was approximately $111 million, which is reflected as subsidiary stock subject to repurchase on the consolidated balance sheet. The repurchase amount will fluctuate with changes in the net asset value per share. At December 31, 2001, the repurchase amount under these agreements was approximately $70 million. See note 16 for details on the Company's acquisition of the remaining shares of Pure which it did not already own, that eliminated the obligation for stock subject to repurchase. -15- Other matters The Company has a lease agreement relating to its Discoverer Spirit deepwater drillship, with a remaining term of approximately three years at September 30, 2002. In 2001, the Company signed a sublease agreement with a third party for a period that began in December 2001 and ended in the middle of September 2002. Under the provisions of that agreement, the third party assumed all of the lease payments to the lessor during the sublease period. The drillship has a minimum daily rate of approximately $219,000. The future remaining minimum lease payment obligation was approximately $240 million at September 30, 2002. 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 but are funded by the Company if exercised. At September 30, 2002, the Company, including its Pure subsidiary, had obtained various surety bonds for approximately $225 million. These surety bonds included a bond for $96 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 $100 million in various other routine performance bonds held by local, city, state and federal agencies. The Company also had obtained approximately $40 million in standby letters of credit at September 30, 2002. 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 $545 million. Guarantees for approximately $332 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 $180 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 $545 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 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. The Company has certain investments in entities that it accounts for under the equity method, such as Colonial Pipeline Company. These entities have approximately $1.7 billion of their own debt obligations that are either fully non-recourse or of limited recourse to the Company. Of the total $1.7 billion in equity investee debt, $1.1 billion belongs to the Colonial Pipeline Company, in which the Company holds a 23.44 percent equity interest. The Company guarantees only $25 million of the total $1.7 billion debt obligations. 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. -16- 13. Financial Instruments and Commodity Hedging Fair values of debt and other long-term instruments - The estimated fair value of the Company's long-term debt at September 30, 2002, including the current portion, was approximately $3.45 billion. The fair value was based on the discounted amounts of future cash outflows using the rates offered to the Company for debt with similar remaining maturities. The estimated fair value of the mandatorily redeemable convertible preferred securities of the Company's subsidiary trust was approximately $515 million at September 30, 2002. The fair value was based on the closing trading price of the preferred securities on September 30, 2002. Commodity hedging activities - During the nine months ended September 30, 2002, the Company recognized $1 million in after-tax losses for the ineffectiveness of both cash flow and fair value hedges. For the third quarter of 2002, the earnings impact of ineffectiveness was immaterial. At September 30, 2002, the Company had approximately $11 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 October 2002 through October 2004. Of this amount, approximately $5 million in after-tax losses are expected to be reclassified to the consolidated earnings statement during the next twelve months. Foreign currency contracts - At September 30, 2002, 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. Nearly all of this amount is expected to be reclassified to the consolidated earnings statement during the next twelve months. Interest rate contracts - At September 30, 2002, 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 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 - The Company has taken appropriate action to help mitigate credit exposure to counterparties whose creditworthiness has deteriorated since the beginning of the year. Counterparty credit lines have been reduced substantially or rescinded entirely where it has been determined that there is unwarranted credit exposure. In other instances, credit assurances in the form of prepayments, letters of credit or guarantees have been obtained to support the credit extension. -17- 14. 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 CONSOLIDATING EARNINGS STATEMENT For the three months ended September 30, 2002 Unocal Non- Unocal CapitalUnion Oil Guarantor Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated ------------------------------------------------------------------------------------------------------------- Revenues Sales and operating revenues $ - $ - $ 310 $ 1,187 $ (210) $ 1,287 Interest, dividends and miscellaneous income 1 8 (68) 65 (9) (3) Gain (loss) on sales of assets - - 1 - - 1 ------------------------------------------------------------------------------------------------------------- Total revenues 1 8 243 1,252 (219) 1,285 Costs and other deductions Purchases, operating and other expenses 1 - (52) 1,077 (210) 816 Depreciation, depletion and amortization - - 81 164 - 245 Impairments - - 2 4 - 6 Dry hole costs - - 5 35 - 40 Interest expense 8 - 31 9 (8) 40 Distributions on convertible preferred securities - 8 - - - 8 ------------------------------------------------------------------------------------------------------------- Total costs and other deductions 9 8 67 1,289 (218) 1,155 Equity in earnings of subsidiaries 101 - (13) - (88) - Earnings from equity investments - - 1 34 - 35 ------------------------------------------------------------------------------------------------------------- Earnings from continuing operations before income taxes and minority interests 93 - 164 (3) (89) 165 ------------------------------------------------------------------------------------------------------------- Income taxes (3) - 63 8 - 68 Minority interests - - - 2 (4) (2) ------------------------------------------------------------------------------------------------------------- Earnings from continuing operations 96 - 101 (13) (85) 99 Earnings from discontinued operations - - - - - - ------------------------------------------------------------------------------------------------------------- Net earnings $ 96 $ - $ 101 $ (13) $ (85) $ 99 =============================================================================================================
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CONDENSED CONSOLIDATING EARNINGS STATEMENT For the three months ended September 30, 2001 Unocal Non- Unocal CapitalUnion Oil Guarantor Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated ------------------------------------------------------------------------------------------------------------- Revenues Sales and operating revenues $ - $ - $ 360 $ 1,479 $ (266) $ 1,573 Interest, dividends and miscellaneous income 1 8 - 8 (9) 8 Gain on sales of assets - - (3) 1 - (2) ------------------------------------------------------------------------------------------------------------- Total revenues - 8 357 1,488 (275) 1,579 Costs and other deductions Purchases, operating and other expenses 1 - 265 1,080 (272) 1,074 Depreciation, depletion and amortization - - 90 156 - 246 Dry hole costs - - 15 38 - 53 Interest expense 8 - 39 10 (9) 48 Distributions on convertible preferred securities - 8 - - - 8 ------------------------------------------------------------------------------------------------------------- Total costs and other deductions 10 8 409 1,284 (281) 1,429 Equity in earnings of subsidiaries 107 - 147 - (254) - Earnings from equity investments - - 2 35 - 37 ------------------------------------------------------------------------------------------------------------- Earnings from continuing operations before income taxes and minority interests 99 - 97 239 (248) 187 ------------------------------------------------------------------------------------------------------------- Income taxes (3) - (10) 90 - 77 Minority interests - - - 2 6 8 ------------------------------------------------------------------------------------------------------------- Earnings from continuing operations 102 - 107 147 (254) 102 Earnings from discontinued operations - - - - - - Cumulative effect of accounting change - - - - - - ------------------------------------------------------------------------------------------------------------- Net earnings $ 102 $ - $ 107 $ 147 $ (254) $ 102 =============================================================================================================
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CONDENSED CONSOLIDATING EARNINGS STATEMENT For the nine months ended September 30, 2002 Unocal Non- Unocal Capital Union Oil Guarantor Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated ------------------------------------------------------------------------------------------------------------------------ Revenues Sales and operating revenues $ - $ - $ 805 $ 3,466 $ (611) $ 3,660 Interest, dividends and miscellaneous income 1 25 (61) 80 (28) 17 Gain (loss) on sales of assets - - 15 (13) - 2 ------------------------------------------------------------------------------------------------------------------------ Total revenues 1 25 759 3,533 (639) 3,679 Costs and other deductions Purchases, operating and other expenses 4 - 434 2,547 (612) 2,373 Depreciation, depletion and amortization - - 261 463 - 724 Impairments - - 23 4 - 27 Dry hole costs - - 22 59 - 81 Interest expense 25 1 109 27 (28) 134 Distributions on convertible preferred securities - 24 - - - 24 ------------------------------------------------------------------------------------------------------------------------ Total costs and other deductions 29 25 849 3,100 (640) 3,363 Equity in earnings of subsidiaries 249 - 313 - (562) - Earnings from equity investments - - 3 120 - 123 ------------------------------------------------------------------------------------------------------------------------ Earnings from continuing operations before income taxes and minority interests 221 - 226 553 (561) 439 ------------------------------------------------------------------------------------------------------------------------ Income taxes (10) - (23) 236 - 203 Minority interests - - - 5 (3) 2 ------------------------------------------------------------------------------------------------------------------------ Earnings from continuing operations 231 - 249 312 (558) 234 Earnings from discontinued operations - - - 1 - 1 Cumulative effect of accounting change - - - - - - ------------------------------------------------------------------------------------------------------------------------ Net earnings $ 231 $ - $ 249 $ 313 $ (558) $ 235 ========================================================================================================================
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CONDENSED CONSOLIDATING EARNINGS STATEMENT For the nine months ended September 30, 2001 Unocal Non- Unocal Capital Union Oil Guarantor Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated ------------------------------------------------------------------------------------------------------------------------ Revenues Sales and operating revenues $ - $ - $ 1,540 $ 5,165 $ (1,242) $ 5,463 Interest, dividends and miscellaneous income 6 25 3 21 (28) 27 Gain on sales of assets - - (2) 1 - (1) ------------------------------------------------------------------------------------------------------------------------ Total revenues 6 25 1,541 5,187 (1,270) 5,489 Costs and other deductions Purchases, operating and other expenses 3 - 932 3,814 (1,269) 3,480 Depreciation, depletion and amortization - - 267 447 - 714 Impairments - - - - - - Dry hole costs - - 49 91 - 140 Interest expense 25 1 124 23 (28) 145 Distributions on convertible preferred securities - 24 - - - 24 ------------------------------------------------------------------------------------------------------------------------ Total costs and other deductions 28 25 1,372 4,375 (1,297) 4,503 Equity in earnings of subsidiaries 658 - 560 - (1,218) - Earnings from equity investments - - 10 118 - 128 ------------------------------------------------------------------------------------------------------------------------ Earnings from continuing operations before income taxes and minority interests 636 - 739 930 (1,191) 1,114 ------------------------------------------------------------------------------------------------------------------------ Income taxes (8) - 96 359 - 447 Minority interests - - - 11 27 38 ------------------------------------------------------------------------------------------------------------------------ Earnings from continuing operations 644 - 643 560 (1,218) 629 Earnings from discontinued operations - - 16 - - 16 Cumulative effect of accounting change - - (1) - - (1) ------------------------------------------------------------------------------------------------------------------------ Net earnings $ 644 $ - $ 658 $ 560 $ (1,218) $ 644 ========================================================================================================================
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CONDENSED CONSOLIDATING BALANCE SHEET At September 30, 2002 Unocal Non- Unocal Capital Union Oil Guarantor Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated ----------------------------------------------------------------------------------------------------------------------------- Assets Current assets Cash and cash equivalents $ - $ - $ 110 $ 165 $ - $ 275 Accounts and notes receivable - net 51 - 148 556 (65) 690 Inventories - - 13 90 - 103 Other current assets - - 86 31 - 117 ----------------------------------------------------------------------------------------------------------------------------- Total current assets 51 - 357 842 (65) 1,185 Investments and long-term receivables - net 4,119 - 4,579 906 (8,055) 1,549 Properties - net - - 2,179 5,605 - 7,784 Other assets 3 541 152 2,094 (2,508) 282 ----------------------------------------------------------------------------------------------------------------------------- Total assets $4,173 $ 541 $ 7,267 $ 9,447 $ (10,628) $ 10,800 ============================================================================================================================ Liabilities and Stockholders' Equity Current liabilities Accounts payable $ - $ - $ 235 $ 689 $ (51) $ 873 Current portion of long-term debt and capital leases - - - 8 - 8 Other current liabilities 44 3 169 324 37 577 ----------------------------------------------------------------------------------------------------------------------------- Total current liabilities 44 3 404 1,021 (14) 1,458 Long-term debt and capital leases - - 2,466 604 - 3,070 Deferred income taxes - - (18) 749 - 731 Accrued abandonment, restoration and environmental liabilities - - 294 301 - 595 Other deferred credits and liabilities 541 - 375 2,352 (2,562) 706 Subsidiary stock subject to repurchase - - - 111 - 111 Minority interests - - - 312 113 425 Company-obligated mandatorily redeemable convertible preferred securities of a subsidiary trust holding solely parent debentures - 522 - - - 522 Stockholders' equity 3,588 16 3,746 3,997 (8,165) 3,182 ----------------------------------------------------------------------------------------------------------------------------- Total liabilities and stockholders' equity $4,173 $ 541 $ 7,267 $ 9,447 $ (10,628) $ 10,800 =============================================================================================================================
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CONDENSED CONSOLIDATING BALANCE SHEET At December 31, 2001 Unocal Non- Unocal Capital Union Oil Guarantor Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated ----------------------------------------------------------------------------------------------------------------------------- Assets Current assets Cash and cash equivalents $ - $ - $ 62 $ 128 $ - $ 190 Accounts and notes receivable - net 51 - 154 693 (51) 847 Inventories - - 3 99 - 102 Other current assets - - 122 34 - 156 ----------------------------------------------------------------------------------------------------------------------------- Total current assets 51 - 341 954 (51) 1,295 Investments and long-term receivables - net 4,032 - 4,143 968 (7,738) 1,405 Properties - net - - 2,149 5,365 - 7,514 Other assets 3 541 214 2,403 (2,950) 211 ----------------------------------------------------------------------------------------------------------------------------- Total assets $4,086 $ 541 $ 6,847 $ 9,690 $ (10,739) $ 10,425 ============================================================================================================================= Liabilities and Stockholders' Equity Current liabilities Accounts payable $ - $ - $ 278 $ 596 $ (51) $ 823 Current portion of long-term debt and capital leases - - - 9 - 9 Other current liabilities 42 3 145 400 - 590 ----------------------------------------------------------------------------------------------------------------------------- Total current liabilities 42 3 423 1,005 (51) 1,422 Long-term debt and capital leases - - 2,181 716 - 2,897 Deferred income taxes - - (71) 698 - 627 Accrued abandonment, restoration and environmental liabilities - - 293 297 - 590 Other deferred credits and liabilities 541 - 312 2,821 (2,950) 724 Subsidiary stock subject to repurchase - - - 70 - 70 Minority interests - - - 309 140 449 Company-obligated mandatorily redeemable convertible preferred securities of a subsidiary trust holding solely parent debentures - 522 - - - 522 Stockholders' equity 3,503 16 3,709 3,774 (7,878) 3,124 ----------------------------------------------------------------------------------------------------------------------------- Total liabilities and stockholders' equity $4,086 $ 541 $ 6,847 $ 9,690 $ (10,739) $ 10,425 =============================================================================================================================
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CONDENSED CONSOLIDATING CASH FLOWS For the nine months ended September 30, 2002 Unocal Non- Unocal Capital Union Oil Guarantor Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated ------------------------------------------------------------------------------------------------------------------------- Cash Flows from Operating Activities $128 $ - $ 43 $1,061 $ - $1,232 Cash Flows from Investing Activities Capital expenditures and acquisitions (includes dry hole costs) - - (303) (945) - (1,248) Proceeds from sales of assets and discontinued operations - - 23 41 - 64 ------------------------------------------------------------------------------------------------------------------------- Net cash used in investing activities - - (280) (904) - (1,184) ------------------------------------------------------------------------------------------------------------------------- Cash Flows from Financing Activities Change in long-term debt and capital leases - - 284 (114) - 170 Dividends paid on common stock (147) - - - - (147) Minority interests - - - ( 6) - ( 6) Other 19 - 1 - - 20 ------------------------------------------------------------------------------------------------------------------------- Net cash provided by (used in) financing activities (128) - 285 (120) - 37 ------------------------------------------------------------------------------------------------------------------------- Net increase in cash and cash equivalents - - 48 37 - 85 ------------------------------------------------------------------------------------------------------------------------- Cash and cash equivalents at beginning of period - - 62 128 - 190 ------------------------------------------------------------------------------------------------------------------------- Cash and cash equivalents at end of period $ - $ - $110 $165 $ - $ 275 =========================================================================================================================
CONDENSED CONSOLIDATING CASH FLOWS For the nine months ended September 30, 2001 Unocal Non- Unocal Capital Union Oil Guarantor Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated ------------------------------------------------------------------------------------------------------------------------- Cash Flows from Operating Activities $132 $ - $ 694 $ 954 $ - $1,780 Cash Flows from Investing Activities Capital expenditures and acquisitions (includes dry hole costs) - - (526) (1,267) - (1,793) Proceeds from sales of assets and discontinued operations - - 47 4 - 51 ------------------------------------------------------------------------------------------------------------------------- Net cash used in investing activities - - (479) (1,263) - (1,742) ------------------------------------------------------------------------------------------------------------------------- Cash Flows from Financing Activities Change in long-term debt and capital leases - - (105) 351 - 246 Dividends paid on common stock (146) - - - - (146) Minority interests - - - ( 17) - ( 17) Other 14 - 1 - - 15 ------------------------------------------------------------------------------------------------------------------------- Net cash provided by (used in) financing activities (132) - (104) 334 - 98 ------------------------------------------------------------------------------------------------------------------------- Net increase in cash and cash equivalents - - 111 25 - 136 ------------------------------------------------------------------------------------------------------------------------- Cash and cash equivalents at beginning of period 1 - 84 150 - 235 ------------------------------------------------------------------------------------------------------------------------- Cash and cash equivalents at end of period $ 1 $ - $195 $175 $ - $ 371 =========================================================================================================================
-24- 15. Segment Data The Company's reportable segments are: Exploration and Production, Trade, Midstream, and Geothermal and Power Operations. General corporate overhead, unallocated costs and other miscellaneous operations, including real estate, carbon and minerals and activities relating to businesses that were sold, are included under the Corporate and Other heading.
------------------------------------------------------------------------ Segment Information Exploration & Production Trade For the Three Months North America International ended September 30, 2002 Millions of dollars Lower 48 Alaska Canada Far East Other ------------------------------------------------------------------------ Sales & operating revenues $ 120 $ 64 $ 43 $ 271 $ 39 $ 623 Other income (loss) (a) 2 - (1) - 1 (1) Inter-segment revenues 210 - - 59 37 - ------------------------------------------------------------------------ Total 332 64 42 330 77 622 Earnings (loss) from equity investments - - - 9 2 1 Earnings (loss) from continuing operations 13 10 (2) 129 7 (1) Earnings from discontinued operations - - - - - - ------------------------------------------------------------------------ Net earnings (loss) 13 10 (2) 129 7 (1) Assets (at September 30, 2002) 3,228 336 1,088 2,723 834 187 ------------------------------------------------------------------------
------------------------------------------------------------------------------------ Midstream Geothermal Corporate & Other Total & Power Admin Net Environ- Operations & Interest mental & General Expense Litigation Other (b) ------------------------------------------------------------------------------------ Sales & operating revenues $ 58 $ 28 $ - $ - $ - $ 41 $ 1,287 Other income (loss) (a) 1 (8) - 3 - 1 (2) Inter-segment revenues 3 - - - - (309) - ------------------------------------------------------------------------------------ Total 62 20 - 3 - (267) 1,285 Earnings (loss) from equity investments 15 (3) - - - 11 35 Earnings (loss) from continuing operations 17 5 (21) (28) (14) (16) 99 Earnings from discontinued operations - - - - - - - ------------------------------------------------------------------------------------ Net earnings (loss) 17 5 (21) (28) (14) (16) 99 Assets (at September 30, 2002) 504 517 - - - 1,383 10,800 ------------------------------------------------------------------------------------ (a) Includes interest, dividends and miscellaneous income, and gain (loss) on sales of assets. (b) Includes eliminations and consolidation adjustments.
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------------------------------------------------------------------------ Segment Information Exploration & Production Trade For the Three Months North America International ended September 30, 2001 Millions of dollars Lower 48 Alaska Canada Far East Other ------------------------------------------------------------------------ Sales & operating revenues $ 158 $ 86 $ 59 $ 254 $ 35 $ 861 Other income (loss) (a) - - (2) (3) 7 - Inter-segment revenues 265 - - 45 23 - ----------------------------------------------------------------------- Total 423 86 57 296 65 861 Earnings (loss) from equity investments (2) - - 10 2 - Earnings from continuing operations 51 17 6 109 2 3 ----------------------------------------------------------------------- Net earnings 51 17 6 109 2 3 Assets (at December 31, 2001) 3,345 344 1,015 2,463 741 156 -----------------------------------------------------------------------
------------------------------------------------------------------------------------ Midstream Geothermal Corporate & Other Total & Power Admin Net Environ- Operations & Interest mental & General Expense Litigation Other (b) ------------------------------------------------------------------------------------ Sales & operating revenues $ 48 $ 46 $ - $ - $ - $ 26 $ 1,573 Other income (loss) (a) - 6 - 6 - (8) 6 Inter-segment revenues 2 - - - - (335) - ----------------------------------------------------------------------------------- Total 50 52 - 6 - (317) 1,579 Earnings (loss) from equity investments 17 (2) - - - 12 37 Earnings (loss) from continuing operations 13 2 (19) (31) (28) (23) 102 ----------------------------------------------------------------------------------- Net earnings (loss) 13 2 (19) (31) (28) (23) 102 Assets (at December 31, 2001) 479 594 - - - 1,288 10,425 ----------------------------------------------------------------------------------- (a) Includes interest, dividends and miscellaneous income, and gain (loss) on sales of assets. (b) Includes eliminations and consolidation adjustments.
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----------------------------------------------------------------------- Segment Information Exploration & Production Trade For the Nine Months North America International ended September 30 2002 Millions of dollars Lower 48 Alaska Canada Far East Other ----------------------------------------------------------------------- Sales & operating revenues $ 357 $ 188 $ 143 $ 765 $ 99 $ 1,723 Other income (loss) (a) 6 - (1) - 1 (1) Inter-segment revenues 610 - - 173 78 1 ----------------------------------------------------------------------- Total 973 188 142 938 178 1,723 Earnings (loss) from equity investments - - - 26 6 1 Earnings (loss) from continuing operations 37 (1) (5) 332 31 1 Earnings from discontinued operations - - - - - - ----------------------------------------------------------------------- Net earnings (loss) 37 (1) (5) 332 31 1 Assets (at September 30, 2002) 3,228 336 1,088 2,723 834 187 -----------------------------------------------------------------------
------------------------------------------------------------------------------------ Midstream Geothermal Corporate & Other Total & Power Admin Net Environ- Operations & Interest mental & General Expense Litigation Other (b) ------------------------------------------------------------------------------------ Sales & operating revenues $ 197 $ 89 $ - $ - $ - $ 99 $ 3,660 Other income (loss) (a) 3 (4) - 11 - 4 19 Inter-segment revenues 9 - - - - (871) - ------------------------------------------------------------------------------------ Total 209 85 - 11 - (768) 3,679 Earnings (loss) from equity investments 52 (1) - - - 39 123 Earnings (loss) from continuing operations 59 25 (64) (93) (50) (38) 234 Earnings from discontinued operations - - - - - 1 1 ------------------------------------------------------------------------------------ Net earnings (loss) 59 25 (64) (93) (50) (37) 235 Assets (at September 30, 2002) 504 517 - - - 1,383 10,800 ------------------------------------------------------------------------------------ (a) Includes interest, dividends and miscellaneous income, and gain (loss) on sales of assets. (b) Includes eliminations and consolidation adjustments.
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----------------------------------------------------------------------- Segment Information Exploration & Production For the Nine Months North America International Trade ended September 30, 2001 Millions of dollars Lower 48 Alaska Canada Far East Other ----------------------------------------------------------------------- Sales & operating revenues $ 486 $ 221 $ 188 $ 755 $ 109 $ 3,289 Other income (loss) (a) 1 - (1) (9) 6 (1) Inter-segment revenues 1,237 - - 155 84 1 ----------------------------------------------------------------------- Total 1,724 221 187 901 199 3,289 Earnings from equity investments 12 - - 29 2 - Earnings from continuing operations 434 49 17 328 29 10 Earnings from discontinued operations - - - - - - Cumulative effect of accounting change - - - - - - ----------------------------------------------------------------------- Net earnings 434 49 17 328 29 10 Assets (at December 31, 2001) 3,345 344 1,015 2,463 741 156 -----------------------------------------------------------------------
------------------------------------------------------------------------------------ Midstream Geothermal Corporate & Other Total & Power Admin Net Environ- Operations & Interest mental & General Expense Litigation Other (b) ------------------------------------------------------------------------------------ Sales & operating revenues $ 187 $ 135 $ - $ - $ - $ 93 $ 5,463 Other income (loss) (a) 2 13 - 19 - (4) 26 Inter-segment revenues 6 - - - - (1,483) - ----------------------------------------------------------------------------------- Total 195 148 - 19 - (1,394) 5,489 Earnings (loss) from equity investments 45 (2) - - - 42 128 Earnings (loss) from continuing operations 40 5 (63) (96) (78) (46) 629 Earnings from discontinued operations - - - - - 16 16 Cumulative effect of accounting change - - - - - (1) (1) ----------------------------------------------------------------------------------- Net earnings (loss) 40 5 (63) (96) (78) (31) 644 Assets (at December 31, 2001) 479 594 - - - 1,288 10,425 ----------------------------------------------------------------------------------- (a) Includes interest, dividends and miscellaneous income, and gain (loss) on sales of assets. (b) Includes eliminations and consolidation adjustments.
16. Subsequent Event On October 29, 2002, the Company completed its exchange offer for the remaining shares of Pure Resources, Inc. ("Pure"), that it did not already own. In the exchange offer, the Company exchanged 0.74 shares of Unocal common stock for each share of Pure common stock it did not already own. The Company accepted tenders of 16,634,625 Pure shares in the exchange offer, which when combined with the 65 percent of the shares it already owned, represented approximately 97.5 percent of Pure's outstanding common shares. On October 30, 2002, the Company completed a short-form merger to acquire the remaining 2.5 percent of Pure's outstanding shares at the same 0.74 exchange ratio used in the exchange offer. Consequently, Pure is now a wholly owned subsidiary of the Company. This transaction was valued at approximately $390 million and eliminated the minority interest liability relating to Pure and all of the outstanding balance under the caption "Subsidiary stock subject to repurchase" on the Company's consolidated balance sheet. See note 12 for additional information on the "Pure Severance and Employment Agreements". The transaction will be reflected in the Company's fourth quarter results. -28- 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 amended 2001 Annual Report on Form 10-K/A.
CONSOLIDATED RESULTS For the Three Months For the Nine Months Ended September 30, Ended September 30, ------------------------------------------ Millions of dollars 2002 2001 2002 2001 -------------------------------------------------------------------------------- Earnings from continuing operations $ 99 $ 102 $ 234 $ 629 Earnings from discontinued operations - - 1 16 Cumulative effect of accounting change - - - (1) -------------------------------------------------------------------------------- Net earnings $ 99 $ 102 $ 235 $ 644 ================================================================================
Continuing Operations Third Quarter Results: Earnings from continuing operations were $99 million, or 41 cents per share (diluted), in the third quarter of 2002, compared with $102 million, or 42 cents per share (diluted), for the same period a year ago. The decrease was primarily due to lower natural gas production compared with the same period a year ago, principally in the Lower 48 operations, which reflected lower Gulf of Mexico natural gas production primarily from a decline in Ship Shoal Block 295 ("Muni field") production (7 MMcf/d, net of royalty, in the third quarter of 2002 versus 140 MMcf/d, net of royalty, in the third quarter of 2001), the effect of reduced second-half 2001 drilling activity compared with the first half of 2001, and storm-related production curtailments in the Gulf of Mexico. The lower production in the Lower 48 operations was partially offset by higher natural gas production from International operations. Worldwide net daily production in the third quarter of 2002 averaged 466,000 barrels-of-oil equivalent ("BOE") per day compared with 506,000 BOE per day a year ago. The lower worldwide production reduced net earnings by approximately $30 million. The third quarter of 2002 also included an after-tax loss of $5 million in mark-to-market accruals and realized gains/losses for non-hedge commodity derivatives recorded by the Company's Northrock Resources Ltd. ("Northrock") subsidiary, compared with an after-tax gain of $1 million in the same period a year ago. Higher liquids prices partially offset the decline in net earnings by approximately $10 million. In the third quarter of 2002, the Company's worldwide average liquids price was $24.19 per barrel, which was an increase of $1.32 per barrel, or 6 percent, from the same period a year ago. The Company's hedging activity lowered the average liquids price by one cent per barrel in the third quarter of 2002 while the third quarter of 2001 included a gain of one cent per barrel from hedging activities. Dry hole costs and exploration expense were $15 million lower, primarily in International operations, in the third quarter of 2002 compared to the same period a year ago. In addition, improved margins from Midstream operations coupled with improved carbon and mineral results (which are included in the Corporate and Other results) increased net earnings by approximately $10 million in the third quarter of 2002 compared to the same period a year ago. After-tax provisions for environmental and litigation matters were $22 million in the third quarter of 2002, compared with $26 million in the same period a year ago. Nine Months Results: Earnings from continuing operations were $234 million, or 96 cents per share (diluted), in the nine months period of 2002, compared with $629 million, or $2.53 per share (diluted), for the same period a year ago. The decrease was primarily due to lower commodity prices and lower worldwide production. Lower natural gas prices reduced net earnings by approximately $190 million, while lower liquids prices reduced net earnings by approximately $50 million. The Company's worldwide average natural gas price, including a benefit of 4 cents per Mcf from hedging activities, was $2.65 per Mcf for the nine months period of 2002, which was a decrease of 86 cents per Mcf or 25 percent from the $3.51 per Mcf, including a loss of six cents per Mcf from hedging activities, in the same period a year ago. In the nine months period of 2002, the Company's worldwide average liquids price was $21.77 per barrel, including a benefit of one cent per barrel from hedging activities, which was a decrease of $2.12 per barrel, or 9 percent, from the $23.89 per barrel price, including a loss of 3 cents per barrel from hedging activities, from the same period a year ago. -29- The results in the nine months period of 2002 were impacted by lower natural gas production compared with the same period a year ago, which reduced net earnings, by approximately $165 million. Worldwide, net daily production in the nine months period of 2002 averaged 476,000 BOE per day, compared with 506,000 BOE per day a year ago. The lower production was principally in the Lower 48 operations, which reflected lower Gulf of Mexico natural gas production stemming from the decline in Muni field production (11 MMcf/d, net of royalty, in the nine months period of 2002 versus 107 MMcf/d, net of royalty, for the same period a year ago) and the reduction in the second-half 2001 drilling activity. The lower production in the Lower 48 operations was partially offset by higher production from International operations. The results in the nine months period of 2002 included $18 million in higher pension related expenses. The nine months of 2002 included $9 million after-tax in pension related expenses, compared to income of $9 million after-tax in the nine months period of 2001. The results in the nine months period of 2002 included a $12 million after-tax impairment of certain properties in Alaska and a $12 million after-tax restructuring provision for the Gulf Region business unit. The nine months period of 2002 included an after-tax loss of $5 million in mark-to-market accruals and realized gains/losses for non-hedge commodity derivatives by Northrock, compared with an after-tax gain of $5 million in the same period a year ago. These negative results in the nine months period of 2002 were partially offset by $40 million in lower dry hole costs compared with the same period a year ago. In addition, after-tax provisions for environmental and litigation matters were $56 million in the nine months period of 2002, compared with $71 million in the same period a year ago. The nine months period results of 2002 also included a $2 million after-tax gain from an insurance settlement reached with insurers for the recovery of amounts previously paid out by the Company for environmental pollution claims and related costs, as well as a $2 million after-tax gain adjustment related to a Lower 48 prior year asset sale. Discontinued Operations The nine months period of 2002 included a $1 million after-tax gain from discontinued operations, related to a participation payment received from the purchaser of the Company's former West Coast refining, marketing and transportation assets covering price differences between California Air Resources Board Phase 2 gasoline and conventional gasoline. The total after-tax gain in the comparable period of 2001 was $16 million, or 6 cents per share (diluted). Cumulative Effect of Accounting Change In the first quarter of 2001, the Company recorded a one-time non-cash $1 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 No. 133, "Accounting for Derivative Instruments and Hedging Activities". Revenues Total revenues from continuing operations for the third quarter of 2002 were $1.29 billion, compared with $1.58 billion for the same period a year ago. The decrease in the third quarter revenues primarily reflected lower U.S. domestic natural gas and liquids production and reduced marketing activity related to the Company's domestic equity production of crude oil. For the nine months period of 2002, total revenues from continuing operations were $3.68 billion, compared with $5.49 billion for the same period a year ago. The decrease in the nine months results primarily reflected lower average hydrocarbon commodity prices, lower domestic natural gas production and reduced marketing activity related to the Company's domestic equity crude production. -30- Exploration and Production The Company engages in oil and gas exploration, development and production worldwide. The results of this segment are discussed under two geographical breakdowns: North America and International. North America - Included in this category are the U.S. Lower 48, Alaska and Canada oil and gas operations. The emphasis of the U.S. Lower 48 operations is on the onshore, shelf and deepwater areas of the Gulf of Mexico region. The U.S. Lower 48 also includes the consolidated results of Pure Resources, Inc. ("Pure"), which operates primarily in the Permian and San Juan Basins in west Texas and New Mexico, the Gulf of Mexico region and offshore in the Gulf of Mexico. A substantial portion of the crude oil and natural gas produced in the U.S. Lower 48 operations, excluding that of Pure, is sold to the Company's Trade business segment. The remainder of North America production, including that of Pure and of Northrock in Canada, 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, including Pure, uses hydrocarbon derivative financial instruments such as futures, swaps and options to hedge portions of the Company's exposure to commodity price fluctuations. Third Quarter Results: After-tax earnings were $21 million in the third quarter of 2002 compared to $74 million for the same period a year ago, which was a decrease of $53 million. The decrease was primarily due to lower natural gas and liquids production. Lower natural gas production during the third quarter of 2002 compared to the same period a year ago reduced after-tax earnings by approximately $40 million. North America average net daily natural gas production was 867 MMcf/d in the third quarter of 2002 compared to 1,114 MMcf/d in the same period a year ago, which was a decrease of 22 percent. Natural gas production in the Lower 48 averaged 716 MMcf/d in the third quarter of 2002 compared to 939 MMcf/d in the same period a year ago. This decline reflected lower natural gas production from the Gulf of Mexico shelf area including production from the Muni field, which averaged 7 MMcf/d, net of royalty, in the third quarter of 2002 compared to 140 MMcf/d, net of royalty, during the third quarter of 2001. In addition, reduced second-half 2001 drilling activity compared with the first half of 2001 and storm-related production curtailments in the Gulf of Mexico contributed to the production decline. Lower liquids production during the third quarter of 2002 compared to the same period a year ago reduced after-tax earnings by $10 million. North America average net daily liquids production was 92 MBbl/d in the third quarter of 2002 compared to 102 MBbl/d in the same period a year ago, which was a decrease of 10 percent. In addition to lower production, Northrock recorded $5 million in after-tax losses related to mark-to-market accruals and realized gains and losses for non-hedging commodity derivative positions during the third quarter of 2002 compared to an after-tax gain of $1 million in the same period a year ago. Nine Months Results: After-tax earnings were $31 million in the nine months period of 2002 compared to $500 million for the same period a year ago, which was a decrease of $469 million. The decrease was primarily due to lower natural gas and liquids prices and lower natural gas production. The average natural gas price for North America, including a gain of 8 cents per Mcf from hedging activities, was $2.69 per Mcf in the nine months period of 2002 compared to $4.29 per Mcf in the same period a year ago, which included a loss of 11 cents per Mcf from hedging activities. In the nine months period of 2002, the Company's North America average liquids price, including a gain of 2 cents per Bbl from hedging activities, was $21.14 per Bbl compared to $23.39 per Bbl in the same period a year ago, which included a loss of 5 cents per Bbl from hedging activities. The lower natural gas prices reduced after-tax earnings by approximately $200 million, while the lower liquids prices reduced after-tax earnings by approximately $35 million. Natural gas production in North America was 910 MMcf/d in the nine months period of 2002 compared to 1,131 MMcf/d in the same period a year ago. This decline reflected primarily lower natural gas production from the Gulf of Mexico shelf area including production from the Muni field, which averaged 11 MMcf/d, net of royalty, in the nine months period of 2002 compared to 107 MMcf/d, net of royalty, during the nine months period of 2001. In addition, reduced second-half 2001 drilling activity compared with the first half of 2001 was a factor in the lower production levels. Lower natural gas production reduced after-tax earnings by approximately $170 million. -31- The results in the nine months period of 2002 also included the $12 million after-tax impairment in Alaska and the $12 million after-tax restructuring provision for the Gulf Region business unit. The nine months period of 2001 included an after-tax gain of $5 million in mark-to-market accruals and realized gains and losses for non-hedge commodity derivatives by Northrock, while the nine months of 2002 had a $5 million after-tax loss. Dry hole costs in the nine months period of 2002 were lower by $20 million after-tax than in the same period a year ago, primarily due to lower drilling activity in the Gulf of Mexico, partially offset by higher dry hole costs in Alaska. Restructuring: In June 2002, the Company adopted a restructuring plan that resulted in a $12 million after-tax restructuring charge. The restructuring charge covered the costs of terminating approximately 200 employees in the Company's Sugar Land, Texas, office and field locations. All of the affected employees had been terminated as of September 30, 2002. The restructuring plan involved organizational changes to eliminate unnecessary work processes in the Company's Gulf Region business unit, which is part of the U.S. Lower 48 operations. The restructuring charge was included in the results of the U.S. Lower 48 section of the Exploration & Production segment. Cash expenditures related to the restructuring plan are expected to total approximately $9 million in the second half of 2002 and $7 million in 2003. The Company expects the plan to reduce future salaries and benefits by an estimated $20 million pre-tax annually. 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 and development activities primarily in Asia, Latin America and West Africa. Third Quarter Results: After-tax earnings totaled $136 million in the third quarter of 2002 compared to $111 million in the same period a year ago, which was an increase of $25 million. The increase was due to $16 million in higher liquids production, $12 million in lower tax expense due to lower effective tax rates, primarily due to changes in the Thai baht/U.S. dollar exchange rate, $9 million in lower dry hole costs, $6 million in higher natural gas and liquids prices, and $5 million in higher natural gas production. These positive factors were partially offset by $12 million in higher operating expenses and $10 million in higher DD&A expense. Liquids sales volumes increased primarily from oil production in Thailand, which began in the third quarter of 2001. Dry hole costs in the third quarter of 2002 were lower primarily due to exploratory dry holes recorded during the third quarter of 2001 in Brazil and Indonesia. The average liquids price for International operations was $24.80 per Bbl in the third quarter of 2002, which was an increase of $1.15 per Bbl, or 5 percent, from the same period a year ago. Natural gas production in International operations was 942 MMcf/d in the nine months period of 2002 compared to 899 MMcf/d in the same period a year ago. This increase was primarily the result of higher production in Myanmar, Thailand and Bangladesh. Nine Months Results: After-tax earnings totaled $363 million in the nine months period of 2002 compared to $357 million in the same period a year ago, which was an increase of $6 million. The increase was primarily due to $20 million in lower dry holes costs, $13 million in higher liquids and natural gas production, $8 million in higher natural gas prices, and a $4 million gain related to foreign exchange rates. Dry hole costs for the nine months period of 2002 were lower primarily due to the 2001 exploratory dry holes in Brazil and Gabon and lower Indonesia dry holes in the current year. Liquids production increased by approximately 7 percent primarily from higher oil production in Thailand. Natural gas production increased 3 percent, primarily from Myanmar. The average natural gas price for International operations was $2.60 per Mcf in the nine months period of 2002 compared with $2.57 per Mcf in the same period a year ago. These positive factors were partially offset by $17 million in lower liquids prices, $15 million in higher operating expenses and $9 million in higher DD&A expense. The average liquids price for International operations was $22.62 per Bbl in the nine months period of 2002, which was a decrease of $1.98 per Bbl, or 8 percent, from the same period a year ago. -32-
OPERATING HIGHLIGHTS UNOCAL CORPORATION For the Three Months For the Nine Months Ended September 30, Ended September 30, ---------------------------------------- 2002 2001 2002 2001 -------------------------------------------------------------------------------- North America Net Daily Production Liquids (thousand barrels) Lower 48 (a) (b) 52 60 54 58 Alaska 24 26 25 25 Canada 16 16 17 15 -------------------------------------------------------------------------------- Total liquids 92 102 96 98 Natural gas - dry basis (million cubic feet) Lower 48 (a) (b) 716 939 740 922 Alaska 61 83 79 104 Canada 90 92 91 105 -------------------------------------------------------------------------------- Total natural gas 867 1,114 910 1,131 North America Average Prices (excluding hedging activities) (c) (d) Liquids (per barrel) Lower 48 $ 24.76 $ 23.08 $ 22.19 $ 24.71 Alaska $ 22.17 $ 21.58 $ 19.41 $ 22.18 Canada $ 22.70 $ 20.89 $ 20.29 $ 20.74 Average $ 23.70 $ 22.35 $ 21.12 $ 23.44 Natural gas (per mcf) Lower 48 $ 2.95 $ 2.71 $ 2.77 $ 4.71 Alaska $ 1.20 $ 1.57 $ 1.48 $ 1.30 Canada $ 2.08 $ 2.69 $ 2.38 $ 4.90 Average $ 2.73 $ 2.62 $ 2.61 $ 4.40 -------------------------------------------------------------------------------- North America Average Prices (including hedging activities) (c) (d) Liquids (per barrel) Lower 48 $ 24.74 $ 23.11 $ 22.22 $ 24.63 Alaska $ 22.17 $ 21.58 $ 19.41 $ 22.18 Canada $ 22.70 $ 20.89 $ 20.29 $ 20.74 Average $ 23.69 $ 22.37 $ 21.14 $ 23.39 Natural gas (per mcf) Lower 48 $ 2.97 $ 2.97 $ 2.86 $ 4.76 Alaska $ 1.20 $ 1.57 $ 1.48 $ 1.30 Canada $ 2.10 $ 2.76 $ 2.44 $ 3.40 Average $ 2.74 $ 2.85 $ 2.69 $ 4.29 -------------------------------------------------------------------------------- (a) Includes proportional shares of production of equity investees. (b) Includes minority interest shares of : Liquids 8 9 8 9 Natural gas 94 111 96 100 Barrels oil equivalent 24 27 24 25 (c) Excludes Trade segment margins. (d) Excludes gains/losses on derivative positions not accounted for as hedges and ineffective portions of hedges.
-33-
OPERATING HIGHLIGHTS (CONTINUED) UNOCAL CORPORATION For the Three Months For the Nine Months Ended September 30, Ended September 30, ---------------------------------------- 2002 2001 2002 2001 -------------------------------------------------------------------------------- International Net Daily Production (e) Liquids (thousand barrels) Far East 52 49 53 49 Other (a) 20 19 20 19 -------------------------------------------------------------------------------- Total liquids 72 68 73 68 Natural gas - dry basis (million cubic feet) Far East 859 833 855 845 Other (a) 83 66 79 64 -------------------------------------------------------------------------------- Total natural gas 942 899 934 909 International Average Prices (f) Liquids (per barrel) Far East $ 23.93 $ 23.04 $ 21.95 $ 24.02 Other $ 26.94 $ 25.27 $ 24.62 $ 26.04 Average $ 24.80 $ 23.65 $ 22.62 $ 24.60 Natural gas (per mcf) Far East $ 2.68 $ 2.62 $ 2.59 $ 2.54 Other $ 2.80 $ 2.80 $ 2.70 $ 2.90 Average $ 2.69 $ 2.63 $ 2.60 $ 2.57 -------------------------------------------------------------------------------- Worldwide Net Daily Production (a) (b) (e) Liquids (thousand barrels) 164 170 169 166 Natural gas - dry basis (million cubic feet)1,809 2,013 1,844 2,040 Barrels oil equivalent (thousands) 466 506 476 506 Worldwide Average Prices (excluding hedging activities) (c) (d) Liquids (per barrel) $ 24.20 $ 22.86 $ 21.76 $ 23.92 Natural gas (per mcf) $ 2.71 $ 2.63 $ 2.61 $ 3.57 Worldwide Average Prices (including hedging activities) (c) (d) Liquids (per barrel) $ 24.19 $ 22.87 $ 21.77 $ 23.89 Natural gas (per mcf) $ 2.72 $ 2.75 $ 2.65 $ 3.51 -------------------------------------------------------------------------------- (a) Includes proportional shares of production of equity investees. (b) Includes minority interest shares of : Liquids 8 9 8 9 Natural gas 94 111 96 100 Barrels oil equivalent 24 27 24 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.
-34- 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 Company's Exploration and Production segment, excluding Pure, in order to manage the Company's exposure to commodity price changes. The Trade segment also purchases liquids and natural gas from certain of the Company's royalty owners, joint venture partners and unaffiliated oil and gas producing and trading companies for resale. In addition, the segment trades hydrocarbon derivative instruments, for which hedge accounting is not used, to exploit anticipated opportunities arising from commodity price fluctuations. The segment also purchases limited amounts of physical inventories for energy trading purposes when arbitrage opportunities arise. These commodity risk-management and trading activities are subject to internal restrictions, including value at risk limits, which measure the Company's potential loss from likely changes in market prices. Third Quarter Results: The results for the third quarter of 2002 were a loss of $1 million after-tax compared to after-tax earnings of $3 million in the same period a year ago. The lower results reflect decreased domestic natural gas and crude oil marketing activities due to lower production from the U.S. Lower 48 operations of the Company's Exploration and Production segment. Sales and operating revenues were $623 million in the third quarter of 2002 compared to $861 million in the same period a year ago, which was a decrease of $238 million. These revenues represented approximately 48 percent and 55 percent of the Company's total sales and operating revenues for the third quarters of 2002 and 2001, respectively. In the third quarter of 2002, crude oil revenues declined by $189 million, primarily due to reduced activity in the purchase and resale of third party barrels intended to take advantage of marketing opportunities, reflecting management's continued efforts to decrease its outside crude oil purchases for resale due to increased volatility in the oil markets. Natural gas revenues declined by $47 million, primarily due to lower U.S. domestic production volumes. Nine Months Results: After-tax earnings totaled $1 million in the nine months period of 2002 compared to $10 million in the same period a year ago. The lower results reflect decreased domestic natural gas and crude oil marketing activities due to lower production from the U.S. Lower 48 operations of the Company's Exploration and Production segment. Sales and operating revenues were $1.723 billion in the nine months period of 2002 compared to $3.289 billion in the same period a year ago, which was a decrease of $1.566 billion. These revenues represented approximately 47 percent and 60 percent of the Company's total sales and operating revenues for the nine months periods of 2002 and 2001, respectively. In the nine months period of 2002, crude oil revenues declined by $883 million, primarily due to reduced activity in the purchase and resale of third party barrels intended to take advantage of marketing opportunities, reflecting management's continued efforts to decrease its outside crude oil purchases for resale due to increased volatility in the oil markets. Natural gas revenues declined by $686 million primarily due to lower commodity prices and lower U.S. domestic production volumes. MIDSTREAM The Midstream segment is comprised of the Company's equity interests in petroleum pipeline companies, wholly-owned pipeline systems throughout the U.S., and the Company's North America gas storage business. Third Quarter Results: After-tax earnings totaled $17 million in the third quarter of 2002 compared to $13 million in the same period a year ago. The increase was due primarily to $7 million in improved throughput volumes from the pipeline business and $3 million in improved results in the gas storage business, which were partially offset by $4 million in after-tax litigation provision and project impairment charge related to the Colonial Pipeline Company and a $2 million after-tax asset impairment related to another U.S. pipeline company in which the Company owns an equity interest. -35- Nine Months Results: After-tax earnings totaled $59 million in the nine months period of 2002 compared to $40 million in the same period a year ago. The increase was due primarily to $10 million in improved throughput volumes from the pipeline business. In addition, after-tax earnings in the gas storage business in the first nine months of 2002 improved by $9 million compared with the same period a year ago. 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 power plants in Indonesia and equity interests in gas-fired power plants in Thailand. The Company's non-exploration and production business development activities, primarily power-related, are also included in this segment. Third Quarter Results: After-tax earnings totaled $5 million in the third quarter of 2002 compared to $2 million in the same period a year ago. The improved results were due to approximately $9 million after-tax in lower receivable provisions related to geothermal operations in Indonesia, partially offset by lower steam sales due to lower electricity generation. Nine Months Results: After-tax earnings totaled $25 million in the nine months period of 2002 compared to $5 million in the same period a year ago. The improved results were due to approximately $23 million after-tax in lower receivable provisions related to geothermal operations in Indonesia. Agreements Reached on Indonesia Geothermal Contracts: In July 2002, the Company's Unocal Geothermal of Indonesia, Ltd. ("UGI"), subsidiary and Dayabumi Salak Pratama, Ltd. ("DSPL"), a 50-percent equity investee of UGI, reached agreement over pricing and production issues at its Gunung Salak geothermal project in Indonesia with PT. PLN (Persero) ("PLN"), the Indonesian state-owned electricity company, and Pertamina, the Indonesian state-owned oil and natural gas company. Gunung Salak is a 330-megawatt (nominal installed nameplate rating) geothermal production and electricity generation project on the western side of the island of Java. UGI operates the steam fields as a contractor to Pertamina and delivers geothermal steam to PLN, which operates three electricity-generating plants at Salak. UGI also delivers steam to DSPL for three generating plants that supply electricity to PLN on behalf of Pertamina. The new agreement extends the primary terms of the Joint Operation Contract and Energy Sales Contract ("ESC") to 2040. The new agreement increases the Unit Rated Capacities for the generating plants operated by DSPL by 32 megawatts thereby increasing minimum take-or-pay amounts payable under the ESC and also includes a commitment by PLN to accept as much steam and electricity as possible over the take-or-pay quantities in order to meet increased demand. In addition, the agreement reaffirms the Government of Indonesia guarantee of PLN's obligations to UGI, DSPL, Pertamina and the project's lenders. The new agreement lowers the selling price of electricity delivered by DSPL from 8.49 cents per kilowatt-hour (kWh) to 4.45 cents per kWh and steam supplied to PLN by UGI from 4.25 cents per kWh to 3.72 cents per kWh. Under the terms of the amended ESC both the selling price for electricity and the selling price for geothermal steam are indexed for changes in foreign exchange rates and inflation. The new agreement also provides for payment by PLN of a portion of the past due receivable balances to the Company while the Company foregoes a portion of the receivables. In July 2002, the Company received $51 million from PLN in payment of a portion of the past due receivable balances. The Company will retain a receivable balance of $93 million plus interest and expects to collect in full this amount over a period of approximately four years. The remaining part of the outstanding receivables was written-off against a previously established allowance for bad debts. -36- CORPORATE AND OTHER Corporate and Other includes general corporate overhead, miscellaneous operations (e.g., real estate activities, carbon and minerals) and other corporate unallocated costs. Net interest expense represents interest expense, net of interest income and capitalized interest. Third Quarter Results: The after-tax earnings effect for the third quarter of 2002 was a loss of $79 million compared to a loss of $101 million in the same period a year ago. Lower after-tax expenses for environmental and litigation matters benefited the third quarter of 2002, with expenses of $25 million after-tax compared to $30 million after-tax for the same period a year ago. The third quarter of 2002 reflected $10 million in higher results from the carbon, minerals and real estate business activities, compared to the same period a year ago. Net interest expense was $3 million lower in the third quarter of 2002 compared to the same period a year ago, primarily due to higher capitalized interest on development projects. The third quarter of 2002 reflected $3 million in lower employee related compensation, as compared to the third quarter of 2001. The results in the third quarter of 2002 included $7 million in higher pension related expenses. Nine Months Results: The after-tax earnings effect for the nine months period of 2002 was a loss of $245 million compared to a loss of $283 million in the same period a year ago. Lower after-tax provisions for environmental and litigation matters benefited the nine months period of 2002, with expenses of $63 million after-tax compared to $80 million after-tax for the same period a year ago. The nine months period of 2002 also reflected $9 million in higher minerals results, compared to the same period a year ago. Lower income tax related adjustments in the nine months period of 2002, as compared to the same period of 2001, benefited earnings by $11 million. The nine months period of 2002 benefited from a $2 million after-tax gain from an insurance settlement reached with insurers for the recovery of amounts previously paid out for environmental pollution claims and related costs. The nine months period of 2001 included a $10 million pre-tax, or $7 million after-tax, contribution to a charitable foundation, while the comparable period of 2002 included a similar contribution of $3 million pre-tax, or $2 million after-tax. The results for the nine months period of 2002 included $18 million in higher pension related expenses. The nine months of 2002 included $9 million after-tax in pension related expenses, compared to income of $9 million after-tax in the nine months period of 2001. Net interest expense was $3 million lower in the nine months period of 2002, as higher interest expense from a premium on an early repayment of long-term debt was more than offset by higher capitalized interest on development projects. -37-
At At At September 30, December 31, September 30, ------------------------------------------------- Millions of dollars 2002 2001 2001 -------------------------------------------------------------------------------- Current ratio 0.8:1 0.9:1 1.1:1 Total debt and capital leases $ 3,078 $ 2,906 $ 2,859 Trust convertible preferred securities 522 522 522 Stockholders' equity 3,182 3,124 3,201 ------------------------------------------------- Total capitalization $ 6,782 $ 6,552 $ 6,582 ================================================= Floating-rate debt/total debt 21% 8% 6% --------------------------------------------------------------------------------
Cash flows from operating activities, including discontinued operations and working capital and other changes, were $1.23 billion for the nine months period of 2002 compared to $1.78 billion in the same period a year ago. This decrease principally reflected the effects of lower worldwide average natural gas and liquids prices. The decrease was partially offset by $143 million in lower income tax payments, net of refunds, compared to the nine months period of 2001, $30 million from the sale of certain domestic trade receivables during the nine months period of 2002 and the receipt of $51 million from PLN in July 2002 for payment of past due receivables as a result of the agreement reached on the Indonesia geothermal contracts at Gunung Salak. Pre-tax proceeds from asset sales, including those classified as discontinued operations, were $64 million for the nine months period of 2002. Proceeds of approximately $29 million were from the sale, by the Company's Pure subsidiary, of oil and gas producing properties in the U.S. Sale proceeds also included $17 million from various other oil and gas asset sales, $15 million in other miscellaneous properties and $3 million related to a participation payment received from the purchaser of the Company's former West Coast refining, marketing and transportation assets covering price differences between California Air Resources Board Phase 2 gasoline and conventional gasoline. For the nine months period of 2001, pre-tax proceeds from asset sales, including those classified as discontinued operations, were $51 million. The proceeds included $25 million related to a participation payment received from the purchaser of the Company's former West Coast refining, marketing and transportation assets, $14 million from the sale of certain oil and gas properties and $12 million from the sale of miscellaneous assets. Capital expenditures in the nine months period of 2002 were $1.25 billion, compared with $1.26 billion in the same period a year ago. The capital expenditures amount for the nine months period of 2001 excluded $536 million in major acquisitions, which is reflected as a separate line on the consolidated cash flows statement. For the full year 2002, total capital expenditures, excluding major acquisitions, are currently expected to be approximately $1.7 billion. Of this total, about 93 percent is expected to be spent in support of exploration and development programs, evenly split between North America and International operations. The remainder of the capital expenditures will be spent on Midstream and Geothermal and Power operations and corporate-related expenditures. The Company has taken appropriate action to help mitigate credit exposure to counterparties whose creditworthiness has deteriorated since the beginning of the year. Counterparty credit lines have been reduced substantially or rescinded entirely where it has been determined that there is unwarranted credit exposure. In other instances, credit assurances in the form of prepayments, letters of credit or guarantees have been obtained to support the credit extension. -38- The Company's long-term debt, including the current portion, was $3.08 billion at September 30, 2002, compared with $2.91 billion at year-end 2001. This increase primarily reflected commercial paper borrowings made by the Company to fund scheduled maturing fixed-rate debt and for other general corporate purposes (see note 10 for further detail on the Company's long-term debt). On October 3, 2002, the Company issued $400 million principal amount of 5.05 percent notes with a maturity date of October 1, 2012. The net proceeds from the sale of the notes were used to repay most of the outstanding commercial paper borrowings. At October 31, 2002, the Company's outstanding balance of commercial paper borrowings was approximately $55 million compared to $437 million outstanding at September 30, 2002. The Company has two credit facilities in place: a $400 million 364-day credit agreement and a $600 million 5-year credit agreement. On October 7, 2002, the Company extended the 364-day credit agreement to October 6, 2003. The agreements provide for the termination of their 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. Based on current commodity prices and current development projects, the Company does not expect cash generated from operating activities, asset sales and cash on hand in 2002 to be sufficient to cover its operating and capital spending requirements and to meet dividend payments. The Company has substantial borrowing capacity to enable it to meet anticipated and unanticipated cash requirements. The Company relies on the commercial paper market on an interim basis, its accounts receivable securitization program and its revolving credit facilities to cover short-term borrowing requirements. The Company decreased the funding availability of its accounts receivable securitization program to $125 million from $204 million in 2002. At September 30, 2002, the Company had sold $100 million of its domestic trade receivables under this program. The Company also has in place a universal shelf registration statement with an unutilized balance of approximately $739 million at September 30, 2002, under which it issued the $400 million of notes discussed above, leaving $339 million of SEC-registered securities, which can be issued as debt and/or equity securities in the future, 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, i.e., "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. In September 2002, Moody's downgraded the Company's credit rating to Baa2 from Baa1 and maintained a stable rating outlook on the Company. In September 2002, Standard & Poor's affirmed its rating for the Company's long-term debt. Moody's and Standard & Poor's outlook remained stable for the Company's Prime-2 and A-2 commercial paper ratings, respectively. As outlined in the tables on pages 40 and 41 of Management's Discussion and Analysis in Item 7 of the Company's amended 2001 Annual Report on Form 10-K/A, the Company continues to believe that it does not have a liquidity exposure in the event of a further credit rating downgrade. In the event that the Company's credit ratings were to fall to levels that would prohibit it from accessing the commercial paper markets, the Company expects that it would still be able to access funds under its revolving credit facilities. -39- ENVIRONMENTAL MATTERS At September 30, 2002, the Company's reserves for environmental remediation obligations totaled $242 million, of which $126 million were included in current liabilities. During the nine months ended September 30, 2002, cash payments of $77 million were applied against the reserves and $82 million in provisions were added to the reserves balance. 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 $245 million. The Company's total environmental reserve and possible additional liability amounts are grouped into the following four categories.
At September 30, 2002 ---------------------------- Possible Millions of dollars Reserves Additional -------------------------------------------------------------------------------- Superfund and similar sites $ 18 $ 11 Active Company facilities 38 63 Company facilities sold with retained liabilities and former Company-operated sites 90 69 Inactive or closed Company facilities 96 102 -------------------------------------------------------------------------------- Total reserves $ 242 $ 245 ================================================================================
Also see notes 11 and 12 to the consolidated financial statements in Item 1 of this report for additional information on environmental related matters. In the third quarter of 2002, provisions of $33 million were recorded. The provisions reflected an $18 million increase in remediation cost estimates for sites included in the Company's "Inactive or closed Company facilities" category. This additional amount is principally for the decommissioning and decontamination of closed molybdenum and rare earth processing facilities of the Company's Molycorp, Inc. subsidiary in Washington and York, Pennsylvania. As a result of ongoing cooperative efforts between the Company and the Nuclear Regulatory Commission, it was determined that it was probable that additional volumes of low-level radioactive contaminated material, in excess of amounts previously estimated, need to be removed at the York and Washington sites. The provisions also reflected an $11 million increase in cost estimates for sites included in the "Company facilities sold with retained liabilities and former Company-operated sites" category. The provisions for these sites reflects primarily revised remediation cost estimates that the Company has received from the purchaser of service stations, bulk plants, terminals, refineries and pipelines that were part of the Company's "downstream" business sold in 1997. In addition, the provisions include increases for approximately 50 other sites in this category. The remaining $4 million of the provisions relate to six sites in the "Active Company facilities" and Superfund and similar sites" categories of reported remediation costs. Most of the $33 million was included in the Company's reported June 30, 2002 estimate of possible additional remediation costs. Possible additional costs in excess of amounts included in the reserves for remediation obligations decreased by $10 million in the third quarter of 2002. The Company decreased its estimated costs by $5 million for the "Inactive or closed Company facilities" category of sites, primarily for the York and Washington, Pennsylvania facilities. These costs were included in the amounts added to the reserve in the third quarter. Partially offsetting this decrease are additional estimates for the Washington site for the estimated costs to remove and dispose of additional contamination that could be present at the site. Estimated possible additional costs for the "Company facilities sold with retained liabilities and former Company-operated sites" category decreased by $2 million primarily due to adding the estimated costs for the Company's sold downstream assets sold in 1997 to the reserve. Possible additional costs for the "Active Company facilities" category were decreased by $3 million. These costs were also added to the reserve in the third quarter. -40- During the first and second quarters of 2002, provisions of $49 million were added to the reserve balance. Provisions of $33 million were recorded for the "Company facilities sold with retained liabilities and former Company-operated sites" category. These provisions were the result of revised cost estimates related to the anticipated cleanup of the Company's former service stations and distribution facilities throughout the U.S. The provisions also included the estimated cost to cleanup contaminated areas that have been identified at a former oil field in Michigan. Provisions of $9 million were recorded for sites included in the "Inactive or closed Company facilities" category primarily for revised cost estimates related to various remediation projects at the Company's former Guadalupe oil field on the central California coast. Additional accruals of $7 million for the "Superfund and similar sites" category were recorded. The accrual was primarily for the Company's estimated remaining share of oversight and monitoring costs related to the McColl Superfund site in Fullerton, California as the result of a federal appeals court overturning a 1998 court decision that held the federal government responsible for cleanup of the site because of its role in encouraging oil companies to produce gasoline during World War II. 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 51 through 53 of Management's Discussion and Analysis in Item 7 of the Company's amended 2001 Annual Report on Form 10-K/A for a discussion of certain of such conditions and events. 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 events concerning Iraq, and security and other factors. 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. The Company estimates that its net worldwide daily production for 2002 will average between 469,000 and 472,000 BOE. Early in the fourth quarter of 2002, the Company sustained significant, temporary production losses in the Gulf of Mexico as a result of Hurricane Lili. The Company's best estimates for fourth quarter production, including the effect of the hurricane, are between 445,000 and 460,000 BOE per day. The Company estimates net earnings per share to be between 50 and 60 cents in the fourth quarter of 2002. The fourth quarter forecast assumes average NYMEX benchmark prices of $29.75 per barrel of crude oil and $4.10 per MMBtu for North America natural gas. The fourth quarter forecasted earnings are expected to change 4 cents per share for every $1 change in its average worldwide realized price for crude oil and 2 cents per share for every 10-cent change in the Company's average realized North America natural gas price. The fourth quarter forecast also includes pre-tax dry hole costs of $25 to $35 million. In addition, the fourth quarter forecast also includes pre-tax losses, net of insurance recoveries, of approximately $15 million as a result of the damage from Hurricane Lili. The Company estimates net earnings per share to be between $1.46 to $1.56 for the full year 2002. -41- Exploration and Production - North America U.S. Lower 48: Hurricane Lili affected the Eastern Gulf of Mexico around the Company's production base in Ship Shoal, Eugene Island and South Marsh Island. Production shut-ins from the storm and the resulting damage to facilities are having a significant effect on fourth quarter 2002 production. Production losses from shut-ins began on October 2 and were as high as 75,000 BOE per day. By October 10 most of the shut-in production from facilities that did not sustain major damage was restored. Approximately 15,000 BOE per day remains shut in as major facility damage assessments and recovery plans were being completed. The Company has insurance coverage for the damages incurred, subject to a $15 million deductible. The Eastern Gulf area is also where the Company was planning to spend the majority of its development and workover activities in the fourth quarter of 2002. A significant number of these projects are currently delayed pending facility repair. The impact of these project delays on net production is estimated to be around 4,000 BOE per day in the fourth quarter. The Company currently expects to resume production by the end of the year from the remaining damaged facilities. The Company estimates that hurricane-related impacts will lower fourth quarter production by 15,000 to 23,000 BOE per day. The Company is currently drilling its second appraisal well, which was delayed 15 days by hurricanes Isidore and Lili, at the Trident discovery in the deepwater Gulf of Mexico. After completing this well, the Company plans to commence drilling another deepwater prospect by the end of 2002 or early in 2003. In addition, the Company is continuing its participation in the development of the Mad Dog discovery. The Company is continuing to focus its exploration effort on deeper prospects with higher resource potential in the Gulf of Mexico shelf. The Company anticipates selling some of its low margin properties in the Gulf Region towards the end of 2002 or in early 2003. On October 29, 2002, the Company completed its exchange offer for the remaining shares of Pure, that it did not already own. In the exchange offer, the Company exchanged 0.74 shares of Unocal common stock for each share of Pure common stock it did not already own. The Company accepted tenders of 16,634,625 Pure shares in the exchange offer, which when combined with the 65 percent of the shares it already owned, represented approximately 97.5 percent of Pure's outstanding common shares. On October 30, 2002, the Company completed a short-form merger to acquire the remaining 2.5 percent of Pure's outstanding shares at the same 0.74 exchange ratio used in the exchange offer. Consequently, Pure is now a wholly owned subsidiary of the Company. This transaction was valued at approximately $390 million and eliminated the minority interest liability relating to Pure and all of the outstanding balance under the caption "Subsidiary stock subject to repurchase" on the Company's consolidated balance sheet. The transaction will be reflected in the Company's fourth quarter results. As a consequence of the acquisition, Standard & Poor's raised its ratings on Pure to BBB+ from BBB-. Alaska: The Company will be closing two platforms in the Cook Inlet in a move to better manage overall costs. One platform is expected to be shutdown by the end of 2002 and the other is expected to be shutdown by the end of the first quarter of 2003. The two platforms currently have a combined production rate of approximately 900 b/d of oil. In addition, the Company is analyzing a restructuring program to streamline operations and improve profitability. -42- Exploration and Production - International Far East Thailand: The Company's Unocal Thailand, Ltd. ("Unocal Thailand"), subsidiary expects modest production growth in 2003, with the full-year effect of the Phase II development in the northern part of the Pailin field in the B12/27 concession area in the Gulf of Thailand. Unocal Thailand is operator of the field and holds a 35 percent working interest (31 percent net of royalty). The Company also 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). Indonesia: 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. Unocal Rapak is operator of the Rapak PSC area and holds an 80 percent working interest. The Company is also evaluating early development options for the condensate discovered at its deepwater Gendalo-Gandang discovery in the Ganal PSC, offshore Indonesia. The Company's Unocal Ganal, Ltd., subsidiary is the operator of the Ganal PSC and holds an 80 percent working interest. In 2003, the Company expects new production from the deepwater West Seno oil and gas field to come on line in the second quarter. The first phase of development has peak production potential of more than 52,000 BOE per day net to the Company, increasing to more than 65,000 BOE per day with the second phase in 2005. Gross development costs for the first phase are expected to be approximately $460 million, with an additional $225 million for the second phase (Unocal's net share is expected to be approximately $415 million and $200 million for phases 1 and 2, respectively). The Company and its co-venturer are currently working to secure financing for a portion of the total costs through the Overseas Private Investment Corporation ("OPIC"). The Company and its co-venturer expect to complete financing arrangements with OPIC in late 2002, or early 2003 for two loans. One loan is $300 million for the first phase, and the other loan is $50 million for the second phase. Other International Azerbaijan: The Azerbaijan International Operating Company ("AIOC") consortium, in which the Company has a 10.28% working interest, is developing Phases 1 and 2 of the offshore Azeri field in the Azeri-Chirag-Guneshli structure in the Azerbaijan sector of the Caspian Sea. Phase 1 is to develop an estimated 1.5 billion barrels of proved crude oil reserves and Phase 2 is to add approximately the same amount of reserves. The Company has approved the expenditure of $310 million and $400 million for its share of the costs for Phases 1 and 2, respectively. The project is under construction and on schedule with first oil from the Phase 1 Central Azeri platform expected early in 2005. Phase 2 will begin production from two additional platforms in 2006. 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 800 MBbl/d by 2009. Bangladesh: The Company continues to work with the government of Bangladesh and Petrobangla, the state oil and gas company, to develop additional reserves and export natural gas to markets in neighboring India. At October 31, 2002, the Company's business unit in Bangladesh had a gross receivable balance of approximately $33 million relating to invoices billed for natural gas and condensate sales to Petrobangla. Approximately $27 million of the outstanding balance represented past due amounts and accrued interest for invoices covering April 2002 through September 2002. 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. See also note 12 to the consolidated financial statements in Item 1 of this report for information regarding a claim made by Petrobangla in 2002 against one of the Company's subsidiaries for compensation with respect to a 1997 well blowout. -43- Midstream Construction of the Baku-Tbilisi-Ceyhan ("BTC") pipeline started in mid-September. The pipeline project is planned to have a crude oil 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. In late October, the Company signed a definitive agreement to sell certain investment interests in nonstrategic pipelines in the U.S. for approximately $54 million. Closing of the transaction is expected before year-end, subject to regulatory approval and standard closing conditions. Geothermal and Power Operations In the Philippines, negotiations between the Company's wholly-owned subsidiary Philippines Geothermal, Inc. ("PGI") and two government-owned entities the National Power Corporation ("NPC") and the Power Sector Assets and Liabilities Corporation are continuing. These negotiations center on the conversion of PGI's Service Contract into a Steam Sales Agreement, the rehabilitation of NPC's power plants at Mak-Ban and Tiwi on the island of Luzon and the requirement for Filipino ownership. The Company believes that significant progress has been made towards an agreement that will be acceptable to all parties to resolve the outstanding issues. Corporate and Other Recent declines in the equity markets and interest rates have had a negative impact on the Unocal Retirement Plan ("Plan"). The fair value of the Plan's assets at October 22, 2002, was below the Plan's accumulated benefit obligation. Without a substantial rebound in the equity markets before year-end, a calculation based on the current fair value of pension assets would require the Company to take an after-tax charge to stockholders' equity (accumulated other comprehensive income) at December 31, 2002 for an estimated amount of $330 million. The actual charge to accumulated other comprehensive income will vary primarily with future 2002 changes in the equity markets and the resultant change in the fair value of Plan assets and long-term interest rates, but will have no impact on 2002 net earnings. For the full-year 2002, pension expense related to the Company's U.S. based employees is expected to be $14 million after-tax, an increase of approximately $25 million after-tax compared to the full-year 2001. Lower returns and declines on plan assets and the use of a lower discount rate to measure benefit-related liabilities are the principal factors behind the increase in current year expense. Furthermore, continued lower returns and declines on Plan assets would result in increased pension expense in future years. The Company will not be required to make cash contributions to the Plan in 2002, 2003 or 2004. Continued poor returns on Plan assets could result in accelerating the requirement to make cash contributions to the Plan after 2004. -44- Reformulated Gasoline Patents The Company's efforts to enforce its patents for reformulated gasoline continue. In its ongoing lawsuit to collect damages for infringement of the '393 patent from five California refiners, the U.S. District Court in California has determined that the 5.75 cent per gallon royalty rate determined by the jury in the 1997 trial will apply to the defendants' infringing gasoline in California for the period from August 1996 through December 2000. No determination has been made by the Court as to the royalty rate for non-California gasoline in this action. The Company's suit against Valero Energy and its subsidiaries for infringement of the `393 and `126 patents has been temporarily stayed pending additional information on the U.S. Patent and Trademark Office ("PTO") reexaminations. In June 2002, the PTO initially rejected all of the claims of the '126 patent, as it had done earlier with the '393 patent, as part of the reexamination process. In July, the PTO granted a second request for reexamination of the '393 patent based on additional alleged prior art. The second reexamination of the `393 patent has now been merged with the first. The Company is awaiting a response from the PTO to its submission arguing against the initial rejections of both the `393 and `126 patents. The Federal Trade Commission has been conducting a non-public investigation of allegations of anticompetitive conduct in enforcement of the Company's patents. The Company has not received notice of whether a determination or conclusion has been reached as a result of the investigation. FUTURE ACCOUNTING CHANGES In August 2001, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards ("SFAS") No 143, "Accounting for Asset Retirement Obligations". It is effective for fiscal years beginning after June 15, 2002, and it requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred, as a capitalized cost of the long-lived asset and to depreciate it over the useful life of the asset. The Company is currently in the process of evaluating the impact that SFAS No. 143 will have on its financial position and results of operations. In June 2002, the FASB issued 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 and is effective for the Company on January 1, 2003. The Company does not expect the adoption of SFAS No. 146 to have a significant impact on its financial position and results of operations. Other proposed accounting changes considered from time to time by the FASB, the U.S. SEC and the United States Congress could materially impact the Company's reported financial position and results of operations. -45- 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 hydrocarbon 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 for changes in interest rates relates to the Company's long-term debt obligations. The Company manages its exposure to changing interest rates principally through the use of a combination of fixed and floating rate debt. Interest rate risk sensitive derivative financial instruments, such as swaps or options may also be used depending upon market conditions. The Company evaluated the potential effect that near term changes in interest rates would have had on the fair value of its interest rate risk sensitive financial instruments at September 30, 2002. Assuming a ten percent decrease in the Company's weighted average borrowing costs at September 30, 2002, the potential increase in the fair value of the Company's debt obligations and associated interest rate derivative instruments, including the Company's net interests in the debt obligations and associated interest rate derivative instruments of its subsidiaries, would have been approximately $87 million at September 30, 2002. 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 September 30, 2002, 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. -46- Assuming an adverse change of ten percent in foreign exchange rates at September 30, 2002, 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 $14 million at September 30, 2002. 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 historical data and uses a three-day time interval with a 97.5 percent confidence level. The model includes offsetting physical positions for 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 $1 million at September 30, 2002. The value at risk related to hydrocarbon derivatives held for non-hedging purposes was approximately $2 million at September 30, 2002. In order to provide a more comprehensive view of the Company's commodity price risk, a tabular presentation of open hydrocarbon derivatives is also provided. The following table sets forth the future volumes and price ranges of hydrocarbon derivatives held by the Company at September 30, 2002, along with the fair values of those instruments. -47-
Open Hydrocarbon Hedging Derivative Instruments (a) (Thousands of dollars) Fair Value Asset 2002 2003 2004 2005 2006-2009 (Liability) (b)(c) ------------------------------------------------------------------------------------------------------------------------------------ Natural Gas Futures Positions Volume (MMBtu) 1,460,000 - - - - $ 997 Average price, per MMBtu $ 3.50 ------------------------------------------------------------------------------------------------------------------------------------ Natural Gas Swap Positions Pay fixed price Volume (MMBtu) 2,660,500 7,978,000 7,241,000 7,218,000 21,677,000 $ 35,317 Average swap price, per MMBtu $ 2.60 $ 2.45 $ 2.33 $ 2.37 $ 2.47 Receive fixed price Volume (MMBtu) 2,392,000 - - - - $ (3,021) Average swap price, per MMBtu $ 2.77 ------------------------------------------------------------------------------------------------------------------------------------ Natural Gas Basis Swap Positions Volume (MMBtu) 1,794,000 4,745,000 - - - $ 1,138 Average price received, per MMBtu $ 3.82 $ 3.79 Average price paid, per MMBtu $ 3.62 $ 3.63 ------------------------------------------------------------------------------------------------------------------------------------ Natural Gas Collar Positions Volume (MMBtu) 22,186,000 5,956,000 268,500 - - $ (1,626) Average ceiling price, per MMBtu $ 5.05 $ 4.64 $ 5.45 Average floor price, per MMBtu $ 3.36 $ 3.67 $ 2.82 ------------------------------------------------------------------------------------------------------------------------------------ Natural Gas Option (Listed) Call Volume (MMBtu) 180,000 180,000 - - - $ (1) Average Call price $ 5.95 $ 6.35 Put Volume (MMBtu) (7,180,000) (180,000) $ 155 Average Put Price $ 2.87 $ 3.25 ------------------------------------------------------------------------------------------------------------------------------------ Natural Gas Option (OTC) Call Volume (MMBtu) Average Call Price Put Volume (MMBtu) 47,472 - - - - $ 26 Average Put Price $ 3.96 ==================================================================================================================================== ------------------------------------------------------------------------------------------------------------------------------------ Crude Oil Future position Volume (Bbls) 308,000 320,000 - - - $ 2,307 Average price, per Bbl $ 23.44 $ 28.20 ------------------------------------------------------------------------------------------------------------------------------------ Crude Oil Option Put Volume (Bbls) 100,000 - - - - $ (242) Average price, per Bbl $ 29.50 Call Volume (Bbls) (100,000) - - - - $ 130 Average price, per Bbl $ 25.85 ------------------------------------------------------------------------------------------------------------------------------------ Crude Oil Collar Positions Volume (Bbls) 70,364 152,000 90,000 - - $ (670) Average ceiling price, per Bbl $ 28.62 $ 24.64 $ 26.21 Average floor price, per Bbl $ 21.32 $ 19.32 $ 18.67 ==================================================================================================================================== (a) Positions reflect long (short) volumes. (b) Includes $7,118 thousand net claims against counterparties with non-investment grade credit ratings. (c) Includes $8,550 thousand in assumed liabilities which were capitalized as acquisition costs.
-48-
Open Hydrocarbon Non-Hedging Derivative Instruments (a) (Thousands of dollars) Fair Value Asset 2002 2003 (Liability) (b) --------------------------------------------------------------------------------- -------------- ------------------------- Natural Gas Futures Positions Volume (MMBtu) 5,000,000 - $ 368 Average price, per MMBtu $ 3.88 --------------------------------------------------------------------------------------------------------------------------- Natural Gas Swap Positions Pay fixed price Volume (MMBtu) 7,240,000 - $ 1,291 Average swap price, per MMBtu $ 3.72 Receive fixed price Volume (MMBtu) 5,926,717 1,055,347 $ (16,086) Average swap price, per MMBtu $ 3.47 $ 2.99 --------------------------------------------------------------------------------------------------------------------------- Natural Gas Basis Swap Positions Volume (MMBtu) 2,130,000 1,860,000 $ 1,145 Average price received, per MMBtu $ 5.53 $ 4.41 Average price paid, per MMBtu $ 5.05 $ 4.48 --------------------------------------------------------------------------------------------------------------------------- Natural Gas Option (Listed) Call Volume (MMBtu) (16,000,000) - $ (29) Average Call price $ 3.91 Put Volume (MMBtu) (3,000,000) - $ 127 Average Put Price $ 2.76 --------------------------------------------------------------------------------------------------------------------------- Natural Gas Option (Over the Counter) Call Volume (MMBtu) (7,613,050) (3,055,200) $ (5,546) Average Call price $ 5.29 $ 2.55 Put Volume (MMBtu) 380,000 - $ (77) Average Put price $ 2.76 --------------------------------------------------------------------------------------------------------------------------- Natural Gas Spread Option (Over the Counter) NYMEX / IFERC (c) Put Volume (MMBtu) (4,080,000) (8,800,000) $ 573 Average Strike price $ 0.38 $ 0.32 =========================================================================================================================== --------------------------------------------------------------------------------------------------------------------------- Crude Oil Future position Volume (Bbls) (257,000) - $ 2,147 Average price, per Bbl $ 29.51 --------------------------------------------------------------------------------------------------------------------------- Crude Oil Option Put Volume (Bbls) - - $ 15 Average price, per Bbl Call Volumes (Bbls) - - $ (32) Average price, per Bbl --------------------------------------------------------------------------------------------------------------------------- Crude Oil Option (Calender Spread) Put Volume (Bbls) 100,000 400,000 $ (21) Average price, per Bbl $ 0.39 $ 0.45 Call Volumes (Bbls) - (400,000) $ (31) Average price, per Bbl $ 0.83 --------------------------------------------------------------------------------------------------------------------------- Crude Oil Swap Positions Pay fixed price Volume (Bbls) 11,850,006 - $ 10,068 Average swap price, per Bbl $ 27.45 Receive fixed price Volume (Bbls) 12,077,000 - $ (16,688) Average swap price, per Bbl $ 27.03 =========================================================================================================================== (a) Positions reflect long (short) volumes. (b) Includes $1,931 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).
-49- 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. 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 amended Annual Report on Form 10-K/A for the year ended December 31, 2001, in Item 1 of Part II of Unocal's Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2002, in Item 1 of Part II of Unocal's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2002, and in Item 5 of Unocal's Current Report on Form 8-K, dated September 18, 2002, under "Myanmar Litigation". There is incorporated by reference: the information regarding environmental remediation reserves and possible additional remediation costs in notes 11 and 12 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 12 to the consolidated financial statements. See also the discussion under "Reformulated Gasoline Patents" in the Outlook section of Management's Discussion and Analysis of recent developments in certain proceedings in which the Company is seeking to enforce its patents for cleaner-burning gasolines. -50- ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K. (a) Exhibits: The Exhibit Index on page 55 of this report lists the exhibits that are filed as part of this report. (b) Reports on Form 8-K: Filed during the third quarter of 2002: (1) Current Report on Form 8-K, dated June 10, 2002, and filed July 29, 2002, for the purpose of reporting, under Item 5, the Company's second quarter 2002 earnings, the commencement of production from Phase II of the Pailin field in Thailand, Agreements reached on Indonesia Geothermal Contracts, Agrium Inc. Litigation, a Bangladesh-related claim and the Company's 2002 earnings forecast. (2) Current Report on Form 8-K, dated and filed August 2, 2002, for the purpose of reporting, under Item 5, Amendment No. 2 to the Rights Agreement, dated as of August 2, 2002, between Unocal Corporation and Mellon Investor Services LLC. (3) Current Report on Form 8-K, dated August 12, 2002, and filed August 13, 2002, for the purpose of reporting, under Item 9, the certifications filed by the Company's chief executive officer and chief financial officer. (4) Current Report on Form 8-K, dated August 20, 2002, and filed August 22, 2002, for the purpose of reporting, under Item 5, the Company's offer to purchase the minority interest shares in its Pure Resources, Inc. subsidiary. (5) Current Report on Form 8-K, dated September 4, 2002, and filed September 6, 2002, for the purpose of reporting, under Item 5, the Company's third quarter and full year earnings forecast, drilling results of its K-2 well and the mailing of the Pure Resources exchange offer prospectus. (6) Current Report on Form 8-K, dated September 13, 2002, and filed September 18, 2002, for the purpose of reporting, under Item 5, the downgrade by Moody's Investor Services, Inc. of the Company's rating and senior unsecured debt. (7) Current Report on Form 8-K, dated September 18, 2002, and filed September 20, 2002, for the purpose of reporting, under Item 5, an update relating to the Pure Resources exchange offer and a litigation update regarding the Company's Myanmar cases. (8) Current Report on Form 8-K, dated and filed September 25, 2002, for the purpose of reporting, under Item 5, a hydrocarbon sheen near Ranggas 6 location in Makassar Strait, Indonesia. (9) Current Report on Form 8-K, dated and filed September 27, 2002, for the purpose of reporting, under Item 5, a third quarter environmental provision. Filed during the fourth quarter of 2002 to the date hereof: (10) Current Report on Form 8-K, dated October 1, 2002, and filed October 2, 2002, for the purpose of reporting, under Item 5, a revised exchange offer relating to Pure Resources. (11) Current Report on Form 8-K, dated October 8, 2002, and filed October 9, 2002, for the purpose of reporting, under Item 5, an update on hurricane Lili and a revised exchange offer relating to Pure Resources. -51- (12) Amended Current Report on Form 8-K/A, dated September 27, 2002, and filed October 11, 2002 for the purpose of reporting, under Item 5, a third quarter environmental provision. (13) Current Report on Form 8-K, dated October 23, 2002, and filed October 24, 2002, for the purpose of reporting, under Item 5, the Company's third quarter 2002 earnings, the Company's 2002 earnings forecast, the Company's 2003 and beyond production outlook and the extension of the revised exchange offer relating to Pure Resources. (14) Current Report on Form 8-K, dated October 30, 2002, and filed October 31, 2002, for the purpose of reporting, under Item 5, the Company's acquisition of the remaining shares of Pure Resources Inc., which it did not already own. 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. SIGNATURE Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. UNOCAL CORPORATION (Registrant) Dated: November 12, 2002 By: /s/JOE D. CECIL --------------------------------- Joe D. Cecil Vice President and Comptroller (Duly Authorized Officer Principal Accounting Officer) -52- 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 function): (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 the 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. Dated: November 11, 2002 /s/CHARLES R. WILLIAMSON ----------------------------- Charles R. Williamson Chairman of the Board and Chief Executive Officer -53- 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 function): (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 the 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. Dated: November 11, 2002 /s/TERRY G. DALLAS ---------------------------- Terry G. Dallas Executive Vice President and Chief Financial Officer -54- EXHIBIT INDEX 10. Amendments and interpretations of certain compensation plans, effective October 1, 2002. 12.1 Statement regarding computation of ratio of earnings to fixed charges of Unocal Corporation for the nine months ended September 30, 2002 and 2001. 12.2 Statement regarding computation of ratio of earnings to fixed charges of Union Oil Company of California for the nine months ended September 30, 2002 and 2001. Copies of exhibits will be furnished upon request. Requests should be addressed to the Corporate Secretary. -55-