10-K 1 form10k-20031231.txt FORM 10-K UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 Form 10-K [X] Annual Report Pursuant to Section 13 or 15(d) [ ] Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 of the Securities Exchange Act of 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 2003 FOR THE TRANSITION PERIOD FROM TO
COMMISSION FILE NUMBER 1-9210 OCCIDENTAL PETROLEUM CORPORATION (Exact name of registrant as specified in its charter) State or other jurisdiction of incorporation or organization DELAWARE I.R.S. Employer Identification No. 95-4035997 Address of principal executive offices 10889 WILSHIRE BLVD., LOS ANGELES, CA Zip Code 90024 Registrant's telephone number, including area code (310) 208-8800
Securities registered pursuant to Section 12(b) of the Act: TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED 10 1/8% Senior Debentures due 2009 New York Stock Exchange 9 1/4% Senior Debentures due 2019 New York Stock Exchange Oxy Capital Trust I 8.16% Trust Originated Preferred Securities New York Stock Exchange Common Stock New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. [X] YES [ ] NO Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X] Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2). [X] YES [ ] NO The aggregate market value of the voting stock held by nonaffiliates of the registrant was approximately $13.0 billion, computed by reference to the closing price on the New York Stock Exchange composite tape of $33.55 per share of Common Stock on June 30, 2003. Shares of Common Stock held by each executive officer and director have been excluded from this computation in that such persons may be deemed to be affiliates. This determination of affiliate status is not a conclusive determination for other purposes. At January 31, 2004, there were approximately 388,147,906 shares of Common Stock outstanding. DOCUMENTS INCORPORATED BY REFERENCE Portions of the registrant's definitive Proxy Statement, filed in connection with its April 30, 2004, Annual Meeting of Stockholders, are incorporated by reference into Part III. TABLE OF CONTENTS PAGE PART I ITEMS 1 AND 2 Business and Properties........................................................................ 3 General........................................................................................ 3 Oil and Gas Operations......................................................................... 3 Chemical Operations............................................................................ 4 Capital Expenditures........................................................................... 5 Employees...................................................................................... 5 Environmental Regulation....................................................................... 5 Available Information.......................................................................... 5 ITEM 3 Legal Proceedings.............................................................................. 5 ITEM 4 Submission of Matters to a Vote of Security Holders............................................ 6 Executive Officers of the Registrant........................................................... 6 PART II ITEM 5 Market for Registrant's Common Equity and Related Stockholder Matters.......................... 7 ITEM 6 Selected Financial Data........................................................................ 8 ITEM 7 Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) (Incorporating Item 7A)...................................................... 8 2003 Business Environment................................................................. 8 Strategy and Overall Performance.......................................................... 9 Business Review........................................................................... 10 2004 Outlook.............................................................................. 13 Segment Operations........................................................................ 14 Significant Items Affecting Earnings...................................................... 16 Consolidated Operations................................................................... 16 Taxes..................................................................................... 17 Liquidity and Capital Resources........................................................... 17 Analysis of Financial Position............................................................ 18 Off-Balance-Sheet Arrangements............................................................ 19 Lawsuits, Claims, Commitments, Contingencies and Related Matters.......................... 20 Environmental Liabilities and Expenditures................................................ 21 Foreign Investments....................................................................... 23 Critical Accounting Policies and Estimates................................................ 23 Significant Accounting Changes............................................................ 25 Derivative Activities and Market Risk..................................................... 28 Selected Cash-Flow Information............................................................ 30 Safe Harbor Statement Regarding Outlook and Other Forward-Looking Data.................... 31 Report of Management...................................................................... 31 ITEM 8 Financial Statements and Supplementary Data.................................................... 32 Report of Independent Auditors............................................................ 32 Consolidated Statements of Operations..................................................... 33 Consolidated Balance Sheets............................................................... 34 Consolidated Statements of Stockholders' Equity........................................... 36 Consolidated Statements of Comprehensive Income........................................... 36 Consolidated Statements of Cash Flows..................................................... 37 Notes to Consolidated Financial Statements................................................ 38 Quarterly Financial Data (Unaudited)...................................................... 69 Supplemental Oil and Gas Information (Unaudited).......................................... 71 Financial Statement Schedule: Schedule II - Valuation and Qualifying Accounts........................................... 78 ITEM 9 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure........... 79 ITEM 9A Controls and Procedures........................................................................ 79 PART III ITEM 10 Directors and Executive Officers of the Registrant............................................. 79 ITEM 11 Executive Compensation......................................................................... 79 ITEM 12 Security Ownership of Certain Beneficial Owners and Management................................. 79 ITEM 13 Certain Relationships and Related Transactions................................................. 79 ITEM 14 Principal Accountant Fees and Services......................................................... 79 PART IV ITEM 15 Exhibits, Financial Statement Schedules and Reports on Form 8-K................................ 79
PART I ITEMS 1 AND 2 BUSINESS AND PROPERTIES In this report, "Occidental" refers to Occidental Petroleum Corporation, a Delaware corporation, and/or one or more entities in which it owns a majority voting interest (subsidiaries). Occidental's executive offices are located at 10889 Wilshire Boulevard, Los Angeles, California 90024; telephone (310) 208-8800. GENERAL Occidental's principal businesses consist of two industry segments. The oil and gas segment explores for, develops, produces and markets crude oil and natural gas. The chemicals segment manufactures and markets basic chemicals, vinyls and performance chemicals. For financial information about these segments, see Note 15 to the Consolidated Financial Statements of Occidental (Consolidated Financial Statements). For information regarding Occidental's current developments, see the information in the "Management's Discussion and Analysis of Financial Condition and Results of Operations" (MD&A) section of this report. OIL AND GAS OPERATIONS GENERAL Occidental's domestic oil and gas operations are Elk Hills and other smaller locations in California, the Hugoton field in Kansas and Oklahoma, the Permian field in West Texas and New Mexico, and the Gulf of Mexico. International operations are located in Colombia, Ecuador, Oman, Pakistan, Qatar, Russia, United Arab Emirates and Yemen. Occidental also has exploration interests in several other countries. For additional information regarding Occidental's oil and gas segment, see the information under the captions "Business Review - Oil and Gas" and "2004 Outlook - Oil and Gas" in the MD&A section of this report. RESERVES, PRODUCTION AND PROPERTIES The table below shows Occidental's total oil and natural gas reserves and production in 2003, 2002 and 2001. In 2003, including the effect of acquisitions, Occidental replaced 184 percent of its 2003 worldwide combined oil and natural gas production of 200 million barrels of oil equivalent (BOE). See the MD&A section of this report, Note 16 to the Consolidated Financial Statements and the information under the caption "Supplemental Oil and Gas Information" in Item 8 of this report for certain details regarding Occidental's oil and gas reserves, the estimation process and production by country. On May 1, 2003, Occidental reported to the U.S. Department of Energy on Form EIA-28 proved oil and gas reserves at December 31, 2002. The amounts reported were the same as the amounts reported in Occidental's 2002 Annual Report. COMPARATIVE OIL AND GAS RESERVES AND PRODUCTION Oil in millions of barrels; natural gas in billions of cubic feet; total in millions of barrels of oil equivalent
2003 2002 2001 ======================== ============================== =============================== =============================== OIL (a) GAS TOTAL (b) Oil (a) Gas Total (b) Oil (a) Gas Total (b) ------- ------- ------- ------- ------- ------- ------- ------- ------- U.S. Reserves 1,500 1,826 1,805 1,452 1,821 1,755 1,371 1,962 1,698 International Reserves 538 768 666 518 228 556 526 106 543 ------- ------- ------- ------- ------- ------- ------- ------- ------- 2,038 2,594 2,471(c) 1,970 2,049 2,311(c) 1,897 2,068 2,241(c) ======= ======= ======= ======= ======= ======= ======= ======= ======= U.S. Production 93 194 125 85 206 119 78 223 115 International Production 70 27 75 65 23 69 55 18 59 ------- ------- ------- ------- ------- ------- ------- ------- ------- 163 221 200 150 229 188 133 241 174 ======================== ======= ======= ======= ======= ======= ======= ======= ======= =======
(a) Includes natural gas liquids and condensate. (b) Natural gas volumes have been converted to equivalent barrels based on energy content of 6,000 cubic feet (one thousand cubic feet is referred to as an "Mcf") of gas to one barrel of oil. (c) Stated on a net basis and after applicable royalties. Includes reserves related to production-sharing contracts, other economic arrangements and Occidental's share of reserves from equity investees. Proved reserves from production-sharing contracts in the Middle East and from other economic arrangements in the U.S. were 437 million barrels of oil equivalent (MMBOE) and 90 MMBOE in 2003, 324 MMBOE and 94 MMBOE in 2002 and 321 MMBOE and 99 MMBOE in 2001, respectively. 3 COMPETITION AND SALES AND MARKETING As a producer of crude oil and natural gas, Occidental competes with numerous other domestic and foreign producers. Crude oil and natural gas are commodities that are sensitive to prevailing global conditions of supply and demand and are sold at "spot" or contract prices or on futures markets to refiners and other market participants. Occidental competes by developing and producing its worldwide oil and gas reserves cost-effectively and acquiring contracts to explore in areas with known oil and gas deposits. Occidental also competes by increasing production through enhanced oil recovery projects in mature and underdeveloped fields and making strategic acquisitions. Occidental focuses on operations in its core areas of the United States, the Middle East and Latin America. CHEMICAL OPERATIONS GENERAL Occidental manufactures and markets basic chemicals, vinyls and performance chemicals directly and through various affiliates (collectively, OxyChem). OxyChem's operations are affected by cyclical economic factors and by specific chemical-industry conditions. For additional information regarding Occidental's chemical segment, see the information under the captions "Business Review - Chemical" and "2004 Outlook - Chemical" in the MD&A section of this report. PRODUCTS AND PROPERTIES OxyChem, which is headquartered in Dallas, Texas, operates chemical manufacturing plants at 26 sites in the United States. Many of the larger facilities are located in the Gulf Coast region of Texas and Louisiana. In addition, OxyChem operates two chemical-manufacturing plants in Canada and one in Chile. All of OxyChem's manufacturing plants are owned. A number of additional facilities process, blend and store products. OxyChem owns and leases an extensive fleet of railcars. OxyChem also has a 50-percent equity investment in a Brazilian corporation that owns a chlor-alkali plant. BASIC CHEMICALS OxyChem's basic chemicals consist of chlorine, caustic soda, potassium chemicals and their derivatives. Chlorine is used for chemical manufacturing in the chlorovinyl chain and for water treatment. OxyChem produces chlorine in Alabama, Delaware, Louisiana, New York, Texas, Brazil and Chile. Estimated annual capacity, including two temporarily idled plants, at December 31, 2003, was 3.4 million tons in the United States (including the 0.9-million-ton total annual capacity of the OxyVinyls partnership, owned 76 percent by Occidental and 24 percent by PolyOne Corporation) and 0.3 million gross tons in Brazil and Chile. Caustic soda is co-produced with chlorine and is used for pulp and paper production, alumina production and other chemical manufacturing. OxyChem produces caustic soda in Delaware, Louisiana, New York, Texas, Brazil and Chile. Estimated annual capacity, including two temporarily idled plants, at December 31, 2003, was 3.5 million tons in the United States (including the 1-million-ton total annual capacity of the OxyVinyls partnership) and 0.4 million gross tons in Brazil and Chile. Potassium chemicals are used in glass, fertilizer, cleaning products and rubber. OxyChem produces potassium chemicals in Alabama and Delaware. Estimated annual capacity at December 31, 2003, was 429,000 tons. Ethylene dichloride (EDC), a chlorine derivative, is a raw material for vinyl chloride monomer (VCM). OxyChem produces EDC in Louisiana, Texas and Brazil. Estimated annual capacity, including one temporarily idled plant, at December 31, 2003, was 3.0 billion pounds in the United States and 0.3 billion gross pounds in Brazil. VINYLS OxyChem's principal producer of vinyls is its 76-percent interest in the OxyVinyls partnership. OxyChem's vinyls products include polyvinyl chloride (PVC) and its precursors, VCM and EDC. OxyChem produces VCM, which is used as a raw material for PVC, in Texas. At December 31, 2003, estimated annual capacity was 6.2 billion pounds (including the 2.4-billion-pound total annual capacity of OxyMar, which is 67-percent owned by Occidental and 3.8-billion-pound total annual gross capacity of the OxyVinyls partnership). PVC resins are used in piping, electrical insulation, external construction materials, flooring, medical and automotive products and packaging. OxyChem produces PVC resins in Kentucky, New Jersey, Pennsylvania, Texas and Canada. At December 31, 2003, estimated annual capacity was 4.7 billion pounds (including the 4.5-billion-pound gross annual capacity of the OxyVinyls partnership). PERFORMANCE CHEMICALS OxyChem's performance chemicals include chlorinated isocyanurates (estimated capacity of 131 million pounds produced in Illinois and Louisiana), resorcinol (estimated capacity of 52 million pounds produced in Pennsylvania), antimony oxide (estimated capacity of 33 million pounds produced in Texas), mercaptans (estimated capacity of 18 million pounds produced in Texas) and sodium silicates (estimated capacity of 722,000 tons produced in Georgia, Ohio, Illinois, New Jersey, Texas and Alabama). Information regarding production capacity reflects estimated annual capacity at December 31, 2003. 4 RAW MATERIALS Nearly all raw materials used in OxyChem's operations are readily available from a variety of sources. Power is provided by regional public utilities and/or by co-generation facilities. Most of OxyChem's key raw-materials purchases are made through contractual relationships, rather than on the spot market. OxyChem is generally not dependent on any single nonaffiliated supplier for a material amount of its raw-material or energy requirements. Operations have not been curtailed as a result of any supply interruptions. PATENTS, TRADEMARKS AND PROCESSES OxyChem's operations use a large number of patents, trademarks and processes, some of which are proprietary and some of which are licensed. OxyChem does not regard its business as being materially dependent on any single patent, trademark or process. SALES AND MARKETING OxyChem's products are sold to industrial users or distributors located in the United States, largely by its own sales force and in certain export markets. OxyChem sells its products at current market or market-related prices through short- and long-term sales agreements. No significant portion of OxyChem's business is dependent on a single third-party customer. OxyChem generally does not manufacture its products against a backlog of firm orders. COMPETITION Occidental's chemical business competes with numerous producers. Since most of OxyChem's products are commodity in nature, they compete primarily on the basis of price. Because OxyChem's products generally do not occupy proprietary positions, OxyChem endeavors to be an efficient, low-cost producer. CAPITAL EXPENDITURES For information on capital expenditures, see the information under the heading "Capital Expenditures" in the MD&A section of this report. EMPLOYEES Occidental employed 7,133 people at December 31, 2003, 5,697 of whom were located in the United States. Occidental employed 2,995 people in oil and gas operations and 3,087 people in chemical operations. An additional 1,051 people were employed in administrative and headquarters functions. Approximately 640 U.S.-based employees are represented by labor unions. Occidental has a long-standing policy to provide fair and equal employment opportunities to all people without regard to race, color, religion, ethnicity, gender, national origin, disability, age, sexual orientation, veteran status or any other legally impermissible factor. Occidental maintains diversity and outreach programs. ENVIRONMENTAL REGULATION For environmental-regulation information, including associated costs, see the information under the heading "Environmental Liabilities and Expenditures" in the MD&A section of this report. AVAILABLE INFORMATION Occidental makes the following information available free of charge through its website at www.oxy.com: >> Forms 10-K, 10-Q, 8-K and amendments to these forms as soon as reasonably practicable after they are filed electronically with the SEC; >> Other SEC filings, including Forms 3, 4 and 5; and >> Corporate-governance information, including its corporate-governance guidelines, board-committee charters and Code of Business Conduct. Board-committee charters and the Code of Business Conduct are available to stockholders upon request. (See Part III Item 10 of this report for further information.) ITEM 3 LEGAL PROCEEDINGS For information regarding lawsuits, claims, commitments, contingencies and related matters, see the information in Note 9 to the Consolidated Financial Statements. On October 1, 2003, the Environmental Protection Agency (EPA) served one of Occidental's subsidiaries with an administrative compliance order and an administrative complaint alleging certain violations of environmental laws at the subsidiary's Pottstown, Pennsylvania facility. Although the order and complaint do not propose any amount of penalties, Occidental believes the EPA seeks penalties exceeding $100,000. Occidental's subsidiary disputes many of the EPA's allegations. Occidental does not expect the resolution of this matter to have a material effect on its financial condition or results of operations. 5 ITEM 4 SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS No matters were submitted to a vote of Occidental's security holders during the fourth quarter of 2003. EXECUTIVE OFFICERS OF THE REGISTRANT
Age at February 29, Name 2004 Positions with Occidental and Subsidiaries and Five-Year Employment History ----------------------- ------------ --------------------------------------------------------------------------------------- Dr. Ray R. Irani 69 Chairman of the Board of Directors and Chief Executive Officer since 1990; President from 1984 to 1996; Chief Operating Officer from 1984-1990; Director since 1984; member of Executive Committee. Dr. Dale R. Laurance 58 President since 1996; Chairman and Chief Executive Officer of Occidental Oil and Gas Corporation (OOGC) since 1999; Director since 1990; member of Executive Committee. Stephen I. Chazen 57 Chief Financial Officer and Executive Vice President -- Corporate Development since 1999; 1994-1999, Executive Vice President -- Corporate Development. Donald P. de Brier 63 Executive Vice President, General Counsel and Secretary since 1993. Richard W. Hallock 59 Executive Vice President -- Human Resources since 1994. John L. Hurst, III 64 Executive Vice President since 2003; President of Occidental Chemical Corporation (OCC) since 2003; 2001-2003, Executive Vice President -- Chlorovinyls of OCC; 2000-2001, Executive Vice President -- Basic Chemicals of OCC; 1999-2000, Chief Executive Officer of OxyVinyls, LP; 1988-1999, Executive Vice President -- Manufacturing of OCC. John W. Morgan 50 Executive Vice President since 2001; Executive Vice President -- Worldwide Production of OOGC since 2001; 1998-2001, Executive Vice President -- Operations; 1991-1998, Vice President -- Operations. Samuel P. Dominick, Jr. 63 Vice President and Controller since 1991. James R. Havert 62 Vice President and Treasurer since 1998; 1992-1998, Senior Assistant Treasurer.
The current term of employment of each executive officer will expire at the April 30, 2004, organizational meeting of the Occidental Board of Directors or when a successor is selected. 6 PART II ITEM 5 MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS TRADING PRICE RANGE AND DIVIDENDS This section incorporates by reference the quarterly financial data appearing under the caption "Quarterly Financial Data (Unaudited)" in Item 8 and the information appearing under the caption "Liquidity and Capital Resources" in the MD&A section of this report. Occidental's common stock was held by approximately 52,635 stockholders of record at December 31, 2003, with an estimated 188,043 additional stockholders whose shares were held for them in street name or nominee accounts. The common stock is listed and traded principally on the New York Stock Exchange and also is listed on certain foreign exchanges. The quarterly financial data on pages 68 and 69 of this report set forth the range of trading prices for the common stock as reported on the composite tape of the New York Stock Exchange and quarterly dividend information. In 2003, the quarterly declared dividend rate for the common stock was $0.26 per share ($1.04 per year). On February 12, 2004, a quarterly dividend of $0.275 per share ($1.10 per year) was declared on the common stock, payable on April 15, 2004 to stockholders of record on March 10, 2004. The declaration of future cash dividends is a business decision made by the Board of Directors from time to time, and will depend on Occidental's financial condition and other factors deemed relevant by the Board. SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS All of Occidental's equity compensation plans for its employees and non-employee directors, pursuant to which options, rights or warrants may be granted, have been approved by the stockholders. See Note 12 to the Consolidated Financial Statements for further information on the material terms of these plans. The following is a summary of the shares reserved for issuance as of December 31, 2003, pursuant to outstanding options, rights or warrants granted under Occidental's equity compensation plans: (a) Number of (b) Weighted- (c) Number of securities securities to be average remaining available issued upon exercise price for future issuance exercise of out- of outstanding under equity standing options, options, compensation plans warrants and warrants and (excluding securities rights rights in column (a)) ---------------------- ------------------- -------------------------- 23,011,923 $26.53 13,101,112 *
* Includes, with respect to the 1995 Incentive Stock Plan, 1,369,796 shares at maximum target level (684,898 at target level) reserved for issuance pursuant to outstanding performance stock awards, including 717,876 shares at maximum target level (358,938 at target level) eligible for certification in February 2004, and 1,188,596 deferred performance and restricted stock awards and, with respect to the 2001 Incentive Compensation Plan, 1,192,018 shares at maximum target level (596,009 at target level) reserved for issuance pursuant to outstanding performance stock awards, 1,737,874 shares reserved for issuance pursuant to restricted stock awards and 3,971 shares reserved for issuance as dividend equivalents under the 2001 Incentive Compensation Plan. Of the remaining 7,608,857 shares, 7,574,285 shares are available under the 2001 Incentive Compensation Plan, all of which may be issued or reserved for issuance for options, rights and warrants as well as performance stock awards, restricted stock awards, stock bonuses and dividend equivalents and 34,572 shares are available for issuance under the Restricted Stock Plan for nonemployee directors. 7 ITEM 6 SELECTED FINANCIAL DATA FIVE-YEAR SUMMARY OF SELECTED FINANCIAL DATA Dollar amounts in millions, except per-share amounts
For the years ended December 31, 2003 2002 2001 2000 1999 =============================================================== ======== ======== ======== ======== ======== RESULTS OF OPERATIONS (a) Net sales $ 9,326 $ 7,338 $ 8,102 $ 8,504 $ 5,594 Income from continuing operations $ 1,595 $ 1,163 $ 1,179 $ 1,557 $ 461 Net income $ 1,527 $ 989 $ 1,154 $ 1,570 $ 448 Earnings applicable to common stock $ 1,527 $ 989 $ 1,154 $ 1,571 $ 442 Basic earnings per common share from continuing operations $ 4.16 $ 3.09 $ 3.16 $ 4.22 $ 1.28 Basic earnings per common share $ 3.98 $ 2.63 $ 3.10 $ 4.26 $ 1.24 Diluted earnings per common share $ 3.93 $ 2.61 $ 3.09 $ 4.26 $ 1.24 Core earnings (b) $ 1,635 $ 999 $ 1,246 $ 1,349 $ 37 FINANCIAL POSITION (a) Total assets $ 18,168 $ 16,548 $ 17,850 $ 19,414 $ 14,125 Long-term debt, net $ 3,993 $ 3,997 $ 4,065 $ 5,185 $ 4,368 Trust preferred securities (c) $ 453 $ 455 $ 463 $ 473 $ 486 Common stockholders' equity $ 7,929 $ 6,318 $ 5,634 $ 4,774 $ 3,523 CASH FLOW Cash provided by operating activities $ 3,074 $ 2,100 $ 2,566 $ 2,348 $ 1,004 Capital expenditures $ (1,601) $ (1,236) $ (1,308) $ (892) $ (557) Cash (used) provided by all other investing activities, net $ (420) $ (460) $ 657 $ (2,152) $ 2,189 DIVIDENDS PER COMMON SHARE $ 1.04 $ 1.00 $ 1.00 $ 1.00 $ 1.00 BASIC SHARES OUTSTANDING (thousands) 383,943 376,190 372,119 368,750 355,073 --------------------------------------------------------------- -------- -------- -------- -------- --------
(a) See the MD&A and the "Notes to Consolidated Financial Statements" for information regarding accounting changes, asset acquisitions and dispositions, discontinued operations, environmental remediation, other costs and other items affecting comparability. (b) For an explanation of core earnings, see "Significant Items Affecting Earnings" in the MD&A. (c) On January 20, 2004, all of the trust preferred securities were redeemed. ITEM 7 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (MD&A) (INCORPORATING ITEM 7A) In this report, the term "Occidental" refers to Occidental Petroleum Corporation (OPC) and/or one or more entities in which it owns a majority voting interest (subsidiaries). Occidental is divided into two segments: oil and gas and chemical. 2003 BUSINESS ENVIRONMENT OIL AND GAS Oil and gas prices are the key variables that drive the industry's financial performance. Prices can vary significantly, even on a short-term basis. Oil prices continued to strengthen in 2003 over their levels in the previous year. The average West Texas Intermediate (WTI) market price for 2003 was $31.03/barrel (bbl) compared with $26.08/bbl in 2002. NYMEX domestic natural gas prices increased significantly from 2002. For 2003, NYMEX gas prices averaged $5.26/Mcf compared with $3.07/Mcf for 2002. CHEMICAL The sectors of the chemical industry in which Occidental participates showed signs of improvement in 2003 largely due to the improving economy and the continued strength of the building and construction markets. The industry experienced higher product prices for all major commodity chemicals; however, the margin improvement was largely offset by higher costs for key raw materials, primarily energy and ethylene. Domestic chlorine demand dropped slightly in 2003, compared to 2002, as the robust housing sector could not overcome general weakness in other manufacturing markets. However, chlorine prices increased sharply in 2003 from their depressed levels in early 2002 in part due to the tightening of supply resulting from industry capacity reductions and the favorable influence of the strong vinyls (VCM/PVC) demand, mainly in the housing sector. Caustic soda prices began to improve in the 8 second quarter of 2003 but softened late in the year due to pressure to move more caustic soda volume versus chlorine. However, overall caustic soda prices improved for the year. PVC prices improved significantly although the price improvement was largely offset by higher raw material costs. STRATEGY AND OVERALL PERFORMANCE Occidental's overall corporate strategy aims to generate competitive total returns to stockholders and consists of three basic elements: >> Focus on large, long-lived oil and gas assets with growth potential. >> Maintain financial discipline and a strong balance sheet. >> Harvest cash from chemicals. Large, long-lived "legacy" oil and gas assets, like those in California, the Permian Basin in Texas and Qatar, tend to have moderate decline rates, enhanced secondary and tertiary recovery opportunities and economies of scale that lead to cost-effective production. These assets are expected to contribute substantial earnings and cash flow after capital. At Occidental, maintaining financial discipline means prudently investing capital in projects that are expected to generate above-cost-of-capital returns throughout the business cycle. During periods of high commodity prices, Occidental will use the bulk of its cash flow after capital expenditures and dividends to improve future earnings levels by acquiring additional properties with low-risk characteristics or through debt reduction. The chemicals business generates free cash flow. In 2003, free cash flow for the segment was approximately $290 million, which compares favorably with the 10-year annual average. The segment was able to achieve this result despite a difficult year for the chemical industry as a whole. (For a calculation of chemical free cash flow, see "Selected Cash-Flow Information" below.) In order to ensure that its strategic objectives are reached, Occidental's management focuses on the following key business goals over the short term: >> Achieve top quartile performance, compared to peer companies, in return on equity with a below average level of debt. >> Segments are to achieve top quartile performance, compared to peer companies, in return on assets and other measurements unique to that segment. These include profits per unit produced, costs to produce each unit, cash flow per unit, costs to find and develop new reserves and other similar measures. DEBT STRUCTURE Occidental's total debt and total debt-to-capitalization ratios are shown in the table below:
Total Debt-to- Capitalization Date ($ amounts in millions) Total Debt(a) Ratio ============================= ========== ============== 12/31/99 $ 5,427 61% 12/31/00 $ 6,354 57% 12/31/01 $ 4,890 46% 12/31/02 $ 4,759 43% 12/31/03 $ 4,570 37% ----------------------------- ---------- --------------
(a) Includes trust preferred securities (redeemed January 20, 2004), natural gas delivery commitment (which was terminated in 2002), subsidiary preferred stock and capital lease obligations. Occidental's year-end 2003 total debt-to-capitalization ratio has declined to approximately 37 percent from the 61-percent level that existed at the end of 1999, as shown in the table above. The decrease in the total debt-to-capitalization ratio in 2003 compared to 1999 is the result of total debt reductions of 16 percent combined with an increase in stockholders' equity of 125 percent over the same period. RETURN ON EQUITY
Three-Year Average Annual 2003 (a) 2001 - 2003 (b) ============================= ========================== 21.4% 18.5% ----------------------------- --------------------------
(a) The Return on Equity for 2003 was calculated by dividing Occidental's 2003 earnings applicable to common stock by the average equity balance in 2003. (b) The Return on Equity for the three-year period was calculated as the sum of the annual earnings applicable to common stock for each of the three years ended 2003 divided by the sum of the ending equity balances for each year end in the same period. Over the past three years, Occidental has focused on improving its return on equity. In 2003, Occidental's return on equity was 21.4 percent and the three-year average return on equity was 18.5 percent. During the same three-year period, Occidental's equity increased by over 41 percent. OIL AND GAS STRATEGY The oil and gas business strategy has three parts that, together, are focused on adding new oil and natural gas reserves at a pace well ahead of production, while simultaneously keeping finding and development costs among the lowest in the industry: >> Continue to add commercial reserves in and around Occidental's core areas, which are the U.S., Middle East and Latin America, through a combination of focused exploration and development programs. >> Pursue commercial opportunities with host governments in core areas to enhance the development of mature fields with large volumes of remaining oil in place by applying appropriate technology and innovative reservoir-management practices. 9 >> Maintain a disciplined approach in buying and selling assets at attractive prices. Over the past several years, the asset base within each of the core areas has been strengthened. Occidental has invested in assets with higher performance potential and sold properties with low or no current return. The results of these changes are discussed below in "Business Review - Oil and Gas." CHEMICAL STRATEGY OxyChem concentrates on the chlorovinyls chain where it begins with chlorine, which is co-produced with caustic soda, and then converts chlorine and ethylene, through a series of intermediate products, into PVC. OxyChem mainly focuses on being a low-cost producer to maximize its cash flow generation. BUSINESS REVIEW OIL AND GAS Occidental's overall performance during the past several years reflects the successful implementation of its oil and gas business strategy, beginning with the acquisition of the Elk Hills oil and gas field in California. The Elk Hills acquisition was followed in April 2000 by the purchase of Altura Energy in the Permian Basin in West Texas for $3.6 billion and thereafter by several smaller acquisitions. During 2003, Occidental enhanced its industry leading position in the Permian Basin by making several complementary acquisitions. At the end of 2003, the Elk Hills and Permian Basin assets made up 65 percent of Occidental's worldwide proven oil reserves and 45 percent of its proven gas reserves. On a BOE basis, they accounted for 62 percent of Occidental's worldwide reserves. In 2003, the combined production from these assets averaged approximately 265,000 BOE per day, which represents 48 percent of Occidental's total worldwide production. These businesses also contributed approximately 56 percent of oil and gas segment earnings. ELK HILLS Occidental operates the Elk Hills oil and gas field in the southern portion of California's San Joaquin Valley with an approximate 78-percent interest. The field was acquired in 1998 for $3.5 billion and is the largest producer of gas in California. Production in 2003 was approximately 94,000 BOE per day. Since the acquisition date, Elk Hills has generated total net pre-tax cash flow of approximately $3.5 billion, after subtracting $871 million of capital expenditures, and has replaced 109 percent of its total Elk Hills oil and gas production of 207 million BOE. At the end of 2003, the property still had an estimated 444 million BOE of proved reserves, compared to the 425 million BOE that were recorded at the time of the acquisition. Occidental's California natural gas production is declining as it produces the Elk Hills gas cap, but the decline has been mitigated by increased development activities. Total gas production averaged 246 MMcf per day in 2003 compared to 281 MMcf in 2002. PERMIAN BASIN The entire Permian Basin is the largest oil basin in the lower 48 United States and accounts for approximately 15 percent of total U.S. oil production. Occidental is the largest producer in the Permian Basin with approximately 15 percent of the total Permian production. Occidental integrated its acquisition of Altura, which was valued at approximately $3.6 billion, with its previously existing Permian Basin properties in Southwest Texas and Southeast New Mexico. Since the acquisition in 2000, the former Altura properties have generated approximately $2.6 billion in total net pre-tax cash flow, after subtracting capital expenditures of approximately $565 million. One element of Occidental's strategy in the Permian Basin is to acquire producing properties at attractive prices that offer synergies with its existing operations. In 2003, Occidental made a number of complementary acquisitions in the Permian Basin for a total purchase price of $317 million. These acquisitions increased total proven reserves by 103 million BOE for an average cost of $3.08 per BOE. On January 31, 2004, Occidental acquired a 1,300-mile oil gathering and pipeline system in the Permian Basin. This system will allow Occidental to efficiently gather and transport its production to Midland where it has storage facilities. The remainder of the pipeline's capacity will be filled by third party producers. Net Permian oil and gas production averaged 171,000 BOE per day in 2003 compared to 164,000 BOE per day in 2002. Approximately 50 percent of Occidental's Permian Basin production is reliant upon the application of carbon dioxide (CO2) flood technology, an enhanced oil recovery technique. This involves injecting CO2 into oil reservoirs where it acts as a solvent, causing the oil to flow more freely so it can be pumped to the surface. The size of these CO2 flood operations makes Occidental a world leader in the development and application of this technology. THUMS Occidental purchased THUMS, the field contractor for an oil production unit offshore Long Beach, California, in 2000. Occidental's share of production from THUMS is subject to contractual arrangements similar to a production-sharing contract, whereby Occidental's share of production varies inversely with oil prices. For 2003, net production from the THUMS oil property averaged 23,000 barrels per day. 10 GULF OF MEXICO Occidental has a one-third interest in the deep-water Horn Mountain oil field, which is Occidental's only asset in the Gulf of Mexico. BP p.l.c. (BP) is the operator. The field began production in November 2002 and production was increased until it reached platform capacity in the third quarter of 2003. In the fourth quarter of 2003, Occidental's net production at Horn Mountain averaged 28,000 BOE per day. HUGOTON Occidental owns a large concentration of gas reserves, production interests and royalty interests in the Hugoton area of Kansas and Oklahoma. The Hugoton field is the largest natural gas field discovered to date in North America. Occidental's Hugoton operations produced 138,000 Mcf of natural gas and 4,000 barrels of oil per day in 2003. MIDDLE EAST DOLPHIN PROJECT In 2002, Occidental purchased a 24.5-percent interest in the Dolphin Project for $310 million. This investment includes a 24.5-percent interest in Dolphin Energy Limited (Dolphin Energy), the operator of the Dolphin Project. The Dolphin Project consists of two parts: (1) a development and production sharing agreement with Qatar to develop and produce natural gas and condensate in Qatar's North Field for 25 years, with a provision to request a 5-year extension; and (2) the rights for Dolphin Energy to build, own and operate a 260-mile-long, 48-inch export pipeline to transport 2 billion cubic feet per day of dry natural gas from Qatar to markets in the United Arab Emirates (UAE) for the life of the Dolphin Project and longer. The pipeline will have capacity to transport up to 3.2 billion cubic feet per day, which will allow for additional business opportunities. Several important milestones have been reached since Occidental joined the Dolphin Project. In 2002, two development wells were drilled and tested, providing sufficient information to complete the field development plan. In October 2003, Dolphin Energy signed two 25-year contracts to supply approximately one BCF of natural gas per day to two entities in the UAE. A third supply contract with the Emirate of Dubai is currently being negotiated. In addition, other markets for natural gas and hydrocarbon liquids are being pursued. In December 2003, the Government of Qatar approved the final field development plan for the Dolphin Project. Based on the foregoing developments, Occidental recorded 107 million BOE of proved undeveloped oil and gas reserves in 2003. Most recently, in January 2004, Dolphin Energy awarded engineering, procurement and construction contracts for the gas processing and compression plant at Ras Laffan in Qatar as well as for two offshore gas production platforms. The plant will receive wet gas from Dolphin's facilities in Qatar's North Field and will remove hydrocarbon liquids, including condensate and natural gas liquids, for further processing and sale. The resulting dry gas will be compressed and transported to the UAE through Dolphin Energy's pipeline. The projected start-up date for production is in 2006. The Dolphin Project is expected to cost approximately $4.0 billion in total. Occidental expects to invest approximately $1 billion for its 24.5-percent share in the Dolphin Project over the next three years. A portion of the project costs may be project financed. During 2004, Occidental expects to invest approximately $250 to $300 million, which is expected to be provided by Occidental's operating cash flow. This investment is in addition to Occidental's expected 2004 capital expenditures of $1.4 billion that are discussed under "Liquidity and Capital Resources." As the project has not begun operation, no revenue or production costs were recorded in 2003. QATAR By introducing advanced drilling systems and applying new waterflooding and reservoir characterization techniques in the Idd El Shargi North Dome (ISND) field, Occidental has increased production and recoverable reserves from the field. Occidental is moving forward with a second phase under its existing agreement in the development of ISND. The new phase is targeting the development and recovery of additional reserves from ISND. Occidental is also engaged in full-field development of the Idd El Shargi South Dome (ISSD) field which, as a satellite to the North Dome, reduces the overall capital requirement of the two projects. Combined production from the two fields averaged 45,000 barrels per day, net to Occidental, in 2003. Also, see the Dolphin Project discussed above. YEMEN In Yemen, Occidental owns direct working interests in the Masila field in Block 14 (38 percent) and a 40.4-percent interest in the East Shabwa field, comprising a 28.6-percent direct-working interest and a 11.8-percent equity interest in an unconsolidated entity. Occidental's net production averaged 37,000 barrels of oil per day in 2003, with 31,000 coming from the Masila field and the remainder from East Shabwa. OMAN Occidental's Oman business is centered in Block 9 where it holds a 65-percent working interest in the production-sharing contract for this block. Net production to Occidental averaged 12,000 barrels of oil per day in 2003. Occidental has entered into a gas sales and purchase agreement with the Government of Oman to sell approximately 120 million gross cubic feet of natural gas per day from Block 9 operations to the Government. First gas sales are anticipated in mid-2004. This agreement has opened up a market for previously stranded gas that is associated with oil production from the Safah field. Occidental also continues its exploration program in the adjacent Block 27. In 2003, the Government of Oman approved a farm-out of a 35-percent working interest in Block 27 to Mitsui E&P Middle East B.V. (Mitsui). As a result, Occidental and Mitsui now share the same working interest percentages in both Block 9 and Block 27. 11 LIBYA Occidental suspended all activities in Libya in 1986 as a result of economic sanctions imposed by the U.S. government, but continues to hold an interest in the assets that it formerly operated. Since the imposition of sanctions, Occidental has derived no economic benefit from its Libyan interests and has no Libyan assets on its balance sheet. Over the past two years, Occidental representatives have met with Libyan officials, under specific authority and guidelines set by the U.S. Treasury Department's Office of Foreign Assets Control (OFAC), for the purpose of fact-finding and discussing generally the status of its contractual interests and property rights. Recent developments that have led to an improvement in U.S.-Libya relations have given rise to speculation that the sanctions could be eased, or perhaps lifted, in the near future. Until that happens, Occidental will continue complying with the existing sanctions and its OFAC licenses. Occidental remains very interested in returning to Libya, where it had considerable success in finding and developing large volumes of commercial oil reserves. Management is carefully monitoring the dynamics of the evolving U.S.-Libya relationship. OTHER EASTERN HEMISPHERE PAKISTAN Occidental holds oil and gas working interests, that vary from 25 to 50 percent, in four Badin Blocks in Pakistan. BP is the operator. In 2002, Occidental purchased additional interests in two of these blocks from the Government of Pakistan for approximately $72 million. 2003 gross production was 102,000 BOE per day, while Occidental's net share was approximately 22,000 BOE per day. RUSSIA In Russia, Occidental owns 50 percent of a joint venture company, Vanyoganneft, that operates in the western Siberian oil basin. Production for 2003 was approximately 30,000 BOE per day, net to Occidental. LATIN AMERICA COLOMBIA Occidental has a 35-percent net share of production and is the operator of the Cano Limon oil field in Colombia. Cumulative gross production from Cano Limon reached one billion barrels of oil in 2003. Colombia's national oil company, Ecopetrol, operates the Cano Limon-Covenas oil pipeline and marine-export terminal. The pipeline transports oil produced from the Cano Limon field for export to international markets. In addition, Occidental has working interests in three exploration blocks: Rio Aipe (50 percent), Chipiron (88 percent) and Cosecha (75 percent). Production in 2003 approximated 2002 levels as improved security along the export pipeline reduced the number of attacks by local terrorist groups below the peak levels of 2001. Occidental's net share of 2003 production averaged 32,000 barrels of oil per day. Occidental's interests in Colombia account for approximately 1 percent of its worldwide assets, 2 percent of its total worldwide reserves and about 6 percent of its worldwide oil and gas production in 2003. Occidental anticipates that it will recover the proved reserves attributable to its contract. ECUADOR Net production in Block 15, which Occidental operates with a 60-percent working interest, averaged approximately 25,000 barrels of oil per day in 2003. In the second half of 2003, the increased production from the Eden-Yuturi oil field in the southeastern corner of Block 15 coincided with the completion of the Oleoducto de Crudos Pesados (OCP) Ltd. oil export pipeline, in which Occidental has a 14-percent interest. Full field development of the Eden-Yuturi oil field is underway with continued development drilling planned in 2004. In addition, work continues in the producing areas in the western portion of the block at the Indillana complex and the Yanaquincha and Limoncocha fields. These projects are expected to increase production by 20,000 barrels per day, for a total net production of 45,000 barrels per day in 2004. In addition, Occidental has completed extensive 3-D seismic surveys and plans to continue expanding its exploration activities in Block 15 in 2004. Foreign oil companies, including Occidental, have been paying a Value Added Tax (VAT), generally calculated on the basis of 10 to 12 percent of expenditures for goods and services used in the production of oil for export. Until 2001, oil companies, like other companies producing products for export, filed for and received reimbursement of VAT. In 2001, the Ecuador tax authority announced that the oil companies' VAT payments did not qualify for reimbursement. In response, the affected oil companies filed actions in the Ecuador Tax Court to seek a judicial determination that the expenditures are subject to reimbursement. In November 2002, Occidental initiated an international arbitration proceeding against the Ecuadorian Government under the United States-Ecuador bilateral investment treaty based on Occidental's belief that the Ecuadorian Government is arbitrarily and discriminatorily refusing to refund the VAT to Occidental. Arbitration proceedings continue at present. Occidental believes that it has a valid claim for reimbursement under applicable Ecuador tax law and the treaty. In the event of an unfavorable outcome, the potential financial statement effect would not be significant. PRODUCTION-SHARING CONTRACTS Occidental conducts its operations in Qatar, Oman and Yemen under production-sharing contracts and, under such contracts, receives a share of production to recover its costs and an additional share for profit. Occidental's share of production from these contracts decreases when oil prices rise and increases when oil prices decline. Overall, Occidental's net economic benefit from these contracts is greater at higher oil prices. 12 CHEMICAL CHLOR-ALKALI Demand for chlor-alkali products improved throughout the first half of 2003 with combined chlorine and caustic soda prices peaking about mid-year. However, as supply and demand shifted to a more balanced position, prices softened in the latter part of the year. OxyChem's chlor-alkali operating rate for 2003 was 90 percent, approximately matching the industry. Domestic caustic soda pricing improved in the second quarter, but then fell to its lowest level of the year in the fourth quarter. Export pricing for caustic soda remained weak throughout the year as the worldwide supply exceeded demand, exerting downward pressure on pricing. OxyChem maintained its Deer Park chlor-alkali production facility in Houston, Texas and its EDC facility in Ingleside, Texas in standby mode. In June 2003, OxyChem idled a circuit which produced chlorine and caustic soda at its Delaware City plant. These idle facilities will be reactivated upon strengthening in overall economic conditions that leads to improved demand and higher margins for caustic soda. VINYLS Continuing strength in natural gas and ethylene prices pushed costs higher in PVC, and led to price increases of two cents per pound per month for four consecutive months in early 2003, for a total increase of 22-percent. These increases were in addition to the 43-percent increase in PVC resin prices in 2002, which was also driven by rising feedstock and energy costs. Total year 2003 demand was lower by 2 percent compared with 2002. For 2003, ethylene prices rose by over 5.5 cents per pound, and average natural gas costs were nearly $2 per million British Thermal Units (MMBTU) higher than 2002. OxyChem operated its PVC facilities at an average operating rate of 88 percent for 2003, slightly above the North American industry average operating rate of 86 percent. In the fourth quarter of 2003, export markets for both PVC and VCM strengthened notably, helped by VCM outages in the U.S. and overseas. DISPOSITION OF EQUISTAR INTEREST AND ACQUISITION OF LYONDELL INTEREST In August 2002, Occidental sold its 29.5-percent share of Equistar to Lyondell and purchased a 21-percent equity interest in Lyondell. Occidental entered into these transactions to diversify its petrochemicals interest. These transactions reduced Occidental's direct exposure to the inherent volatility in the petrochemicals markets, yet will allow it to participate, through its Lyondell investment, in the economic recovery of the petrochemicals industry. In connection with these transactions, Occidental wrote down its investment in the Equistar partnership to fair value by recording a $412 million pre-tax charge as of December 2001. When this transaction closed in the third quarter of 2002, Occidental recorded an after-tax gain of $164 million. As a result of increases in its investment during 2003, at December 31, 2003, Occidental owned 22 percent (39.5 million shares) of Lyondell stock with a carrying value of $479 million. DISPOSITION OF CHROME AND CALENDERING OPERATIONS In the fourth quarter of 2002, Occidental sold its chrome business at Castle Hayne, North Carolina for $25 million and its plastic calendering operations in Rio de Janeiro, Brazil for a $6 million note receivable. In the third quarter of 2002, Occidental recorded an after-tax impairment charge of $69 million and classified both of these businesses as discontinued operations. CORPORATE AND OTHER Corporate and other includes the investments in Lyondell and Premcor, Inc., a refining business, and a leased co-generation facility in Taft, Louisiana. In 2004, corporate and other will also include the results of a 1,300-mile oil pipeline and gathering system located in the Permian Basin, which was acquired in January 2004 and will be used in corporate-directed oil and gas marketing and trading operations. In July 2001, Occidental sold its interests in a subsidiary that owned a Texas intrastate natural gas pipeline system and also sold its interest in a liquefied natural gas (LNG) project in Indonesia. After-tax proceeds of approximately $750 million from these transactions were used to reduce debt. 2004 OUTLOOK OIL AND GAS The petroleum industry is highly competitive and subject to significant volatility due to numerous market forces. Crude oil and natural gas prices are affected by market fundamentals such as weather, inventory levels, competing fuel prices, overall demand and the availability of supply. In the last half of 2003, worldwide oil prices strengthened due to increasing concerns about the security and availability of ample supplies to meet growing demand. Continued economic growth, resulting in increased demand and concerns about supply availability, could result in continued high prices. A lower growth rate could result in lower crude oil prices. Sustained high oil prices will significantly affect profitability and returns for Occidental and other upstream producers. However, the industry has historically experienced wide fluctuations within price cycles. Although oil prices cannot be predicted with any certainty, the WTI price has averaged approximately $22.50/barrel over the past ten years. While supply-demand fundamentals are a decisive factor affecting domestic natural gas prices over the long term, day-to-day prices may be more volatile in the futures markets, such as on the NYMEX and other exchanges, which make it difficult to forecast prices with any degree of confidence. Over the last ten years, the NYMEX gas price has averaged $3.00 per Mcf. 13 CHEMICAL The chemical business has been profitable historically; however, the average level of earnings has declined over the past several years. The major factors that have an impact on the performance of this business are general economic conditions, including demand for chemical products, energy and feedstock costs, and the effect of changes in available capacity. Over the last five years, the U.S. chemical industry and its primary market, the U.S. based manufacturing industry, have faced significant challenges. Foreign competition continues to make price increases by the U.S. manufacturing industry difficult to achieve. In the chemical industry, increasing natural gas prices, which affect U.S. electricity prices, have sharply reduced, and in many cases eliminated, the domestic chemical industry's natural advantage of proximity to its markets. This has affected basic commodity chemicals such as caustic soda, chlorine and PVC, but is particularly significant for niche specialty products such as resorcinol, mercaptans and antimony-based products. As a result, the U.S. based chemical industry is facing increasing pressure from competitors in both domestic and export markets. Export sales accounted for approximately 17 percent of Occidental's 2003 chemical sales. The end of the most recent recession and resultant world economic recovery is expected to improve the overall outlook. Construction of LNG terminals on the U.S. Gulf Coast could stabilize natural gas prices at a lower-than-current level and thereby help improve the competitive position of efficient Gulf Coast chemical facilities. However, this may not occur in the immediate future. Although Occidental's chemical business is profitable, if U.S. manufacturing becomes non-competitive on a worldwide basis, this could shorten the estimated productive lives of some of Occidental's plants, resulting in higher annual depreciation. Significantly shorter productive lives could also result in asset impairments, including plant closures. It is unlikely that any changes in estimated productive lives would be uniform. While potential impairment charges could have a material impact on the earnings in a discrete period, such changes are unlikely to have a material effect on Occidental's overall financial situation. For additional discussion of the possible financial effect, please see the "Critical Accounting Policies and Estimates" section below in the MD&A. CHLOR-ALKALI Further improvement in chlor-alkali operating rates is expected in 2004 and beyond as domestic demand for chlorine and caustic soda is forecasted to increase 2 percent in 2004. PVC and other downstream derivatives are leading the growth in demand for chlorine. Demand growth for caustic soda is expected to track closely with overall manufacturing activity. With increasing demand and improved capacity utilization, pricing for chlorine is expected to continue to rise compared to 2003. Caustic soda prices should also improve as overall manufacturing demand strengthens. VINYLS Gross domestic product (GDP) growth in the latter part of 2003 and consensus forecasts of 2004 GDP growth exceeding 4 percent for North America are encouraging and suggest a strengthening in the economy that will favorably impact chlorovinyls. Overall, Occidental expects 2-percent growth in vinyls demand in North America in 2004. PVC and VCM operating rates are expected to move upward during the year, also averaging 2 percent higher than 2003 rates. Chlorovinyls supply constraints, together with high energy costs, have created conditions for vinyls price increases early in 2004. Resin producer price increases of 2 cents per pound have taken effect for January, and a second 2 cents per pound increase has been announced for February. In addition, VCM intermediates are expected to be in shorter supply than PVC because of industry capacity reductions and maintenance requirements. Average operating rates for North American VCM producers are expected to exceed 90 percent. The increased demand for chlorine and tighter VCM supplies, due to capacity reductions, is expected to result in supply restrictions for vinyl producers. SEGMENT OPERATIONS The following discussion of Occidental's two operating segments and corporate items should be read in conjunction with Note 15 to the Consolidated Financial Statements. Segment earnings exclude interest income, interest expense, unallocated corporate expenses, discontinued operations and the cumulative effect of changes in accounting principles, but include gains and losses from dispositions of segment assets and results from the segments' equity investments. Foreign income and other taxes and certain state taxes are included in segment earnings based on their operating results. U.S. federal income taxes are not allocated to segments except for amounts in lieu thereof that represent the tax effect of operating charges resulting from purchase accounting adjustments, and the tax effects resulting from major, infrequently occurring transactions, such as asset dispositions that relate to segment results. 14 The following table sets forth the sales and earnings of each operating segment and corporate items: SEGMENT OPERATIONS
In millions, except per share amounts For the years ended December 31, 2003 2002 2001 ================================= ======== ======== ======== SALES Oil and Gas $ 6,003 $ 4,634 $ 5,134 Chemical 3,178 2,704 2,968 Other (a) 145 -- -- -------- -------- -------- $ 9,326 $ 7,338 $ 8,102 ================================= ======== ======== ======== EARNINGS(LOSS) Oil and Gas (b) $ 2,664 $ 1,707 $ 2,845 Chemical (b) 210 275 (399) -------- -------- -------- 2,874 1,982 2,446 Unallocated corporate items Interest expense, net (c) Debt, net (289) (253) (272) Trust preferred distributions and other (44) (47) (56) Income taxes (d) (662) (364) (359) Other (d, e) (284) (155) (580) -------- -------- -------- Income from continuing operations 1,595 1,163 1,179 Discontinued operations, net -- (79) (1) Cumulative effect of changes in accounting principles, net (68) (95) (24) -------- -------- -------- Net Income $ 1,527 $ 989 $ 1,154 ================================= ======== ======== ======== Basic Earnings per Common Share $ 3.98 $ 2.63 $ 3.10 ================================= ======== ======== ========
(a) The 2003 amount represents revenue from a co-generation plant in Taft, Louisiana. (b) Includes U.S. federal tax charge of $6 million related to oil and gas in 2003. Segment earnings in 2002 were affected by $402 million of net credits allocated, comprising $1 million of charges and $403 million of credits in oil and gas and chemical, respectively. The chemical amount includes a $392 million credit for the sale of the Equistar investment, which resulted in a net gain of $164 million. Segment earnings in 2001 were affected by $14 million of net charges allocated, comprising $56 million of charges and $42 million of credits in oil and gas and chemical, respectively. The oil and gas amount includes a charge for the sale of the Indonesian Tangguh LNG project. The chemical amount includes credits for the sale of certain chemical operations. (c) The 2003 amount includes a $61 million interest charge to repay a $450 million senior note that had 10 years of remaining life, but subject to remarketing on April 1, 2003. The 2002 and 2001 amounts are net of $21 million and $102 million, respectively, of interest income on notes receivable from Altura partners. (d) The 2001 tax amount excludes the income tax benefit of $188 million attributed to the sale of the entity that owns a Texas intrastate pipeline system. The tax benefit is included in Other. (e) The 2003 amount includes $58 million of corporate equity-method investment losses and $63 million of environmental remediation expense. The 2002 amount includes $22 million of preferred distributions to the Altura partners, $23 million of environmental remediation expenses and $25 million of corporate equity-method investment losses. The 2001 amount includes the after-tax loss of $272 million related to the sale of the entity that owns a Texas intrastate pipeline system, a $109 million charge for environmental remediation expenses and $104 million of preferred distributions to the Altura partners. OIL AND GAS
In millions, except as indicated 2003 2002 2001 ======================================== ======== ======== ======== SEGMENT SALES $ 6,003 $ 4,634 $ 5,134 SEGMENT EARNINGS $ 2,664 $ 1,707 $ 2,845 CORE EARNINGS (a) $ 2,664 $ 1,707 $ 2,446 NET PRODUCTION PER DAY UNITED STATES Crude oil and liquids (MBBL) California 81 86 76 Permian 150 142 137 Horn Mountain 21 1 -- Hugoton 4 3 -- -------- -------- -------- Total 256 232 213 Natural Gas (MMCF) California 252 286 303 Hugoton 138 148 159 Permian 129 130 148 Horn Mountain 13 -- -- -------- -------- -------- Total 532 564 610 LATIN AMERICA Crude oil & condensate (MBBL) Colombia 37 40 21 Ecuador 25 13 13 -------- -------- -------- Total 62 53 34 MIDDLE EAST Crude oil & condensate (MBBL) Oman 12 13 12 Qatar 45 42 43 Yemen 35 37 33 -------- -------- -------- Total 92 92 88 OTHER EASTERN HEMISPHERE Crude oil & condensate (MBBL) Pakistan 9 10 7 Natural Gas (MMCF) Pakistan 74 63 50 BARRELS OF OIL EQUIVALENT (MBOE) SUBTOTAL CONSOLIDATED SUBSIDIARIES 520 492 452 Colombia-minority interest (5) (5) (3) Russia-Occidental net interest 30 27 27 Yemen-Occidental net interest 2 1 -- -------- -------- -------- TOTAL WORLDWIDE PRODUCTION 547 515 476 ======== ======== ======== AVERAGE SALES PRICES CRUDE OIL PRICES ($ per barrel) U.S. $ 28.74 $ 23.47 $ 21.74 Latin America $ 27.21 $ 23.14 $ 20.10 Middle East (b) $ 27.81 $ 24.13 $ 23.00 Other Eastern Hemisphere $ 26.61 $ 23.02 $ 22.64 Total consolidated subsidiaries $ 28.18 $ 23.56 $ 21.91 Other interests $ 15.95 $ 14.80 $ 15.57 Total worldwide $ 27.25 $ 22.91 $ 21.41 GAS PRICES ($ per thousand cubic feet) U.S. $ 4.81 $ 2.89 $ 6.40 Other Eastern Hemisphere $ 2.04 $ 2.08 $ 2.29 Total worldwide $ 4.45 $ 2.81 $ 6.09 EXPENSED EXPLORATION (c) $ 139 $ 176 $ 184 CAPITAL EXPENDITURES Development $ 1,097 $ 897 $ 918 Exploration $ 43 $ 55 $ 86 Acquisitions and other (d, e) $ 97 $ 86 $ 134 ---------------------------------------- -------- -------- --------
(a) For an explanation of core earnings, see "Significant Items Affecting Earnings." (b) These amounts exclude implied taxes. (c) Includes dry hole write-offs and lease impairments of $80 million in 2003, $96 million in 2002 and $99 million in 2001. (d) Includes capitalized portion of injected CO2 of $48 million, $42 million and $48 million in 2003, 2002 and 2001, respectively. (e) Includes mineral acquisitions but excludes significant acquisitions individually discussed in this report. 15 Core earnings in 2003 were $2.7 billion compared with $1.7 billion in 2002. The increase in core earnings primarily reflects the impact of higher crude oil and natural gas prices and higher crude oil production volumes, partially offset by lower natural gas production volumes, higher depreciation, depletion and amortization (DD&A) rates and increased costs. CHEMICAL
In millions, except as indicated 2003 2002 2001 ========================================= ======== ======== ======== SEGMENT SALES $ 3,178 $ 2,704 $ 2,968 SEGMENT EARNINGS (LOSS) $ 210 $ 275 $ (399) CORE EARNINGS (a) $ 210 $ 111 $ 13 KEY PRODUCT PRICE INDEXES (1987 through 1990 average price = 1.0) Chlorine 1.72 1.01 0.74 Caustic soda 0.84 0.71 1.33 Ethylene dichloride 1.16 1.01 0.61 PVC commodity resins (b) 0.89 0.73 0.68 KEY PRODUCT VOLUMES Chlorine (thousands of tons) (c) 2,733 2,807 2,847 Caustic soda (thousands of tons) 2,764 2,717 2,857 Ethylene dichloride (thousands of tons) 546 573 735 PVC commodity resins (millions of pounds) 3,954 4,132 3,950 CAPITAL EXPENDITURES (d) $ 345 $ 109 $ 112 ----------------------------------------- -------- -------- --------
(a) For an explanation of core earnings, see "Significant Items Affecting Earnings." (b) Product volumes produced at former PolyOne facilities, now part of OxyVinyls, are excluded from the product price indexes. (c) Product volumes include those manufactured and consumed internally. (d) The 2003 amount includes $180 million for the purchase of a previously leased facility in LaPorte, Texas and $44 million related to the exercise of purchase options for certain leased railcars. Core earnings were $210 million in 2003, compared with $111 million in 2002. The increase in core earnings reflects the impact of higher sales prices for all major products (PVC, EDC, chlorine and caustic), partially offset by higher energy and ethylene costs. SIGNIFICANT ITEMS AFFECTING EARNINGS Occidental's results of operations often include the effects of significant transactions and events affecting earnings that vary widely and unpredictably in nature, timing and amount. Therefore, management uses a measure called "core earnings", which excludes those items. This non-GAAP measure is not meant to disassociate those items from management's performance, but rather is meant to provide useful information to investors interested in comparing Occidental's earnings performance between periods. Reported earnings are considered representative of management's performance over the long term. Core earnings is not considered to be an alternative to operating income in accordance with generally accepted accounting principles. SIGNIFICANT ITEMS AFFECTING EARNINGS
Benefit (Charge) (in millions) 2003 2002 2001 ========================================= ======== ======== ======== TOTAL REPORTED EARNINGS $ 1,527 $ 989 $ 1,154 ========================================= ======== ======== ======== OIL AND GAS Segment Earnings $ 2,664 $ 1,707 $ 2,845 Less: Gain on sale of interest in the Indonesian Tangguh LNG Project (a) -- -- 399 -------- -------- -------- Segment Core Earnings $ 2,664 $ 1,707 $ 2,446 ----------------------------------------- -------- -------- -------- CHEMICAL Segment Results $ 210 $ 275 $ (399) Less: Gain on sale of Equistar investment (a) -- 164 -- Equistar writedown -- -- (412) -------- -------- -------- Segment Core Earnings $ 210 $ 111 $ 13 ----------------------------------------- -------- -------- -------- CORPORATE Results $ (1,347) $ (993) $ (1,292) Less: Loss on sale of pipeline-owning entity (a) -- -- (272) Settlement of state tax issue -- -- 70 Debt repayment fee (61) -- -- Changes in accounting principles, net (a) (68) (95) (24) Discontinued operations, net (a) -- (79) (1) Tax effect of pre-tax adjustments 21 -- 148 ----------------------------------------- -------- -------- -------- TOTAL CORE EARNINGS $ 1,635 $ 999 $ 1,246 ========================================= ======== ======== ========
(a) These amounts are shown after-tax. CONSOLIDATED OPERATIONS SELECTED REVENUE ITEMS
In millions 2003 2002 2001 ==================================== ======== ======== ======== Net sales $ 9,326 $ 7,338 $ 8,102 Interest, dividends and other income $ 89 $ 143 $ 223 Gains on disposition of assets, net $ 32 $ 10 $ 10 ------------------------------------ -------- -------- --------
The increase in sales in 2003, compared to 2002, primarily reflects higher crude oil, natural gas and chemical prices and higher crude oil production volumes, partially offset by lower natural gas production volumes. The decrease in sales in 2002, compared to 2001, primarily reflects lower natural gas and chemical prices and lower natural gas and chemical volumes, partially offset by higher crude oil prices and production. Interest, dividends and other income in 2002 and 2001 includes interest income on the notes receivable from the Altura partners of $21 million and $102 million, respectively. Occidental exercised an option in May 2002 to redeem the sellers' remaining partnership interests in exchange for the notes receivable. Gains on disposition of assets in 2003 include the final gain of $22 million on the sale of the remaining Continental Shelf Gulf of Mexico (GOM) assets to Apache Corporation. Gains on disposition of assets in 2001 include the gain of $454 million on the sale of the interest in the Tangguh LNG project and the loss of $459 million on the sale of its interests in a subsidiary that owned a Texas natural gas intrastate pipeline system. 16 SELECTED EXPENSE ITEMS
In millions 2003 2002 2001 =================================== ======== ======== ======== Cost of sales $ 3,988 $ 3,385 $ 3,626 Selling, general and administrative and other operating expenses $ 855 $ 677 $ 668 Depreciation, depletion and amortization $ 1,177 $ 1,012 $ 965 Exploration expense $ 139 $ 176 $ 184 Interest and debt expense, net $ 332 $ 295 $ 401 ----------------------------------- -------- -------- --------
Cost of sales increased in 2003, compared to 2002, due mainly to oil and gas volume increases and higher energy and feedstock costs in the chemical segment. The 2003 amount also includes $156 million for the costs of operating a co-generation facility. Cost of sales decreased in 2002, compared to 2001, due mainly to lower chemical raw material costs, partially offset by volume increases in oil and gas. Selling, general and administrative and other operating expenses increased in 2003 compared with 2002. The increases were in several areas. General and administrative costs increased in both oil and gas and corporate infrastructure and general support areas. In addition, non-operating costs were generally higher in international operations, mainly Latin America. Higher oil and gas production taxes reflected the overall increase in worldwide production. Also, additional expense resulted from adoption of the new asset retirement obligation accounting standard. Selling, general and administrative and other operating expenses increased in 2002, compared to 2001, due mainly to $42 million of chemical asset writedowns in 2002, partially offset by other charges in 2001. The increase in DD&A in 2003, compared to 2002, and 2002, compared to 2001, was primarily due to the increase in oil and gas production from the prior year and a higher DD&A rate in 2003. The decrease in exploration expense in 2003, compared to 2002, was primarily due to lower dry hole write-offs and impairment costs and lower seismic, geological and geophysical costs in 2003. The increase in interest and debt expense in 2003, compared to 2002, reflected a pre-tax debt repayment charge of $61 million in 2003, partially offset by lower interest rates and lower average debt levels. In addition, since Occidental adopted Statement of Financial Accounting Standards (SFAS) No. 150 in July 2003, the 2003 interest expense amount includes six months of interest that had been classified as distributions on trust preferred securities prior to the adoption (see below). The decrease in interest and debt expense in 2002, compared to 2001, reflects lower average debt levels and lower interest rates. OTHER ITEMS
In millions 2003 2002 2001 ============================= ======== ======== ======== Provision for income taxes $ 1,227 $ 422 $ 556 Minority interest $ 62 $ 77 $ 143 Loss from equity investments $ 9 $ 261 $ 504 ----------------------------- -------- -------- --------
The increase in the provision for income taxes in 2003, compared to 2002, reflected an increase in income before taxes. In addition, the 2002 provision for income taxes includes an income tax benefit of $406 million for the sale of the Equistar investment. The 2001 provision includes income tax benefits of $172 million resulting from the write-down of the Equistar investment, $188 million from the sale of the entity that owns a Texas intrastate natural gas pipeline system, and a $45 million after-tax settlement of a state-tax issue. The decrease in minority interest in 2003, compared to 2002, resulted from the July 1, 2003 adoption of SFAS No. 150, which required distributions on trust preferred securities to be classified as interest expense. These distributions were previously recorded in minority interest. The decrease in minority interest in 2002, compared to 2001, was due to an $84 million decrease in preferred distributions to the Altura partners. The remaining Altura partnership interests were redeemed in May 2002. The 2002 loss from equity investments includes a pre-tax loss of $242 million from the sale of the Equistar investment in August 2002. The loss from equity investments in 2001 includes a $412 million pre-tax write-down of Equistar and a loss of $89 million from the Equistar equity investment. TAXES Deferred tax liabilities were $926 million at December 31, 2003, net of deferred tax assets of $839 million. The current portion of the deferred tax assets of $75 million is included in prepaid expenses and other. The net deferred tax assets are expected to be realized through future operating income and reversal of taxable temporary differences. LIQUIDITY AND CAPITAL RESOURCES FINANCING ACTIVITY During 2003, Occidental strengthened its liquidity position, generating approximately $3 billion in cash from operations. Although future volatility in commodity prices may result in varying operating cash flows, Occidental believes that cash on hand, cash generated from operating activities, unused committed bank credit lines and other sources of funds, such as debt issued in the capital markets and the receivables sale program, will be adequate to satisfy its future financial obligations and liquidity needs. As of December 31, 2003, available borrowing capacity under Occidental's unused committed bank credit lines was $1.5 billion. Occidental had approximately $683 million in cash on hand at December 31, 2003, an increase of $537 million from 2002. A portion of the year-end 2003 cash balance was used to redeem all of the outstanding 8.16 percent Trust Preferred Redeemable Securities (trust preferred securities) on January 20, 2004. The trust preferred securities were redeemed at par plus accrued interest, resulting in a decrease in current liabilities of approximately $453 million. 17 In 2003, Occidental recorded a pre-tax interest charge of $61 million to repay a $450 million 6.4-percent senior notes issue that had ten years of remaining life, but was subject to remarketing on April 1, 2003. Occidental refinanced $300 million of this amount and paid the remaining $150 million out of existing cash. In 2002, Occidental filed a shelf registration statement for up to $1 billion of various securities, including senior debt securities. In November 2002, Occidental issued $175 million of 4-percent Medium-Term Senior Notes, Series C, and $75 million of 4.101-percent Medium-Term Senior Notes, Series C, due 2007 for general corporate purposes. In March 2003, Occidental issued $300 million of 4.25-percent Medium-Term Senior Notes and used the proceeds to refinance a portion of the $450 million senior notes discussed above. Occidental has $450 million of securities remaining under the shelf registration. In 2002, Occidental repaid and or redeemed approximately $198 million of senior notes and medium-term notes and a subsidiary of Occidental issued $75 million of preferred stock. Occidental retains all common shares of the subsidiary and elects the majority of the directors. The subsidiary is the holding company for a number of international subsidiaries of Occidental. In the event that the subsidiary fails to pay preferred dividends for two consecutive quarters or upon the occurrence of certain other events, the holder of the preferred stock could gain control of the subsidiary's board of directors. CASH FLOW ANALYSIS
In millions 2003 2002 2001 ===================================== ======== ======== ======== Net cash provided by operating activities $ 3,074 $ 2,100 $ 2,566 ------------------------------------- -------- -------- --------
The increase in operating cash flow in 2003 compared to 2002 resulted from higher net income. The lower operating cash flow in 2002, compared with 2001, results from lower core earnings and higher working capital usage. Non-cash charges in 2003 include deferred compensation, stock incentive plan amortization and environmental remediation accruals. Non-cash charges in 2002 include environmental remediation accruals and the asset writedown for two chemical facilities. Non-cash charges in 2001 include environmental remediation accruals. 2002 and 2001 also include charges for employee benefit plans and other items.
In millions 2003 2002 2001 ===================================== ======== ======== ======== Net cash used by investing activities $ (2,021) $ (1,696) $ (651) ------------------------------------- -------- -------- --------
The 2003 amount includes several Permian Basin acquisitions totaling $317 million. The 2002 amount includes approximately $349 million for a 24.5-percent interest in the Dolphin Project and Dolphin Energy, including $39 million for historical costs. The 2001 amount includes the gross proceeds of $863 million from the sale of the entity that owns a Texas intrastate pipeline system and the sale of Occidental's interest in the Tangguh LNG project in Indonesia. Also, see the "Capital Expenditures" section below.
In millions 2003 2002 2001 ===================================== ======== ======== ======== Net cash used by financing activities $ (516) $ (456) $ (1,814) ------------------------------------- -------- -------- --------
The 2003 amount includes net debt repayments of $334 million. The 2002 amount reflects the net $179 million buyout of the natural gas delivery commitment and $72 million of net proceeds from the issuance of a subsidiary's preferred stock. The 2001 amount reflects the repayment of $2.3 billion of long-term and non-recourse debt, partially offset by proceeds of $861 million from new long-term debt. Occidental paid common stock dividends of $392 million in 2003, $375 million in 2002 and $372 million in 2001. CAPITAL EXPENDITURES
In millions 2003 2002 2001 ============================= ======== ======== ======== Oil and Gas $ 1,237 $ 1,038 $ 1,138 Chemical 345 109 112 Corporate and other 19 89 58 -------- -------- -------- TOTAL $ 1,601 $ 1,236 $ 1,308 ============================= ======== ======== ========
The 2003 chemical amount includes $180 million for the purchase of a previously leased facility in LaPorte, Texas and $44 million related to the exercise of purchase options for certain leased railcars. Occidental's capital spending estimate for 2004 is approximately $1.4 billion. In addition, Occidental expects to spend $250 million to $300 million on the Dolphin Project. A majority of the capital spending will be allocated to oil and gas, with the main focus on Qatar, Elk Hills and the Permian Basin. Commitments at December 31, 2003, for major capital expenditures during 2004 and thereafter were approximately $201 million. Occidental will fund these commitments and capital expenditures with cash from operations and, as needed, with proceeds from existing credit facilities. ANALYSIS OF FINANCIAL POSITION The changes in the following components of Occidental's balance sheet are discussed below: SELECTED BALANCE SHEET COMPONENTS
In millions 2003 2002 ================================================ ======== ======== Cash and cash equivalents $ 683 $ 146 Trade receivables, net $ 804 $ 608 Income tax receivable $ 20 $ 150 Investments in unconsolidated subsidiaries $ 1,155 $ 1,056 Property, plant and equipment, net $ 14,005 $ 13,036 Current maturities of long-term debt and capital lease liabilities $ 23 $ 206 Accounts payable $ 909 $ 785 Accrued liabilities $ 877 $ 914 Dividends payable $ 101 $ 193 Trust preferred securities - current $ 453 $ -- Trust preferred securities - non-current $ -- $ 455 Other deferred credits and liabilities $ 2,407 $ 2,228 Stockholders' equity $ 7,929 $ 6,318 ------------------------------------------------ -------- --------
18 The higher balance in cash and cash equivalents at December 31, 2003, compared to December 31, 2002, reflects the build-up of cash, part of which was used to redeem $453 million of trust preferred securities in January 2004. The higher balance in trade receivables at December 31, 2003, compared with December 31, 2002, reflects higher product prices and sales volumes during the fourth quarter of 2003 versus 2002 in the oil and gas segment. The decrease in income tax receivable was due to a 2002 tax receivable from the Equistar sale that was received in 2003. The higher balance in investments in unconsolidated entities primarily reflects a capital contribution to the Ecuador OCP pipeline investment, additional purchases of Lyondell and Premcor stock and mark-to-market increases in the available-for-sale Premcor investment. The increase in the net balance in property, plant and equipment reflects capital spending, the addition of the acquired Permian Basin assets and the consolidation of the OxyMar property, plant and equipment as a result of the adoption of Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 46, partially offset by depreciation, depletion and amortization. The decrease in current maturities of long-term debt is due to the fact that a lower level of debt will mature in 2004. The increase in accounts payable is due to higher payable balances in the oil and gas marketing and trading operations. The decrease in accrued liabilities is due to lower mark-to-market adjustments on derivative financial instruments. The decrease in dividends payable is due to the fact that at the end of 2002, there were two quarters of dividend accruals due to an early declaration in 2002 of a dividend paid in 2003. At June 30, 2003, pursuant to the adoption of SFAS No. 150, the trust preferred securities were reclassified to long-term liabilities. At year-end 2003, they were further reclassified to current liabilities as Occidental announced its intention to redeem all of the trust preferred securities. On January 20, 2004, all of the trust preferred securities were redeemed. Other deferred credits and liabilities include deferred compensation, other post-retirement benefits, environmental remediation reserves, asset retirement obligations and other deferred items. The increase in other deferred credits and liabilities in 2003, compared to 2002, was primarily due to the asset retirement obligation that was recorded in connection with the adoption of SFAS No. 143. The increase in stockholders' equity primarily reflects net income and issuance of new stock related to options exercised, partially offset by dividends on common stock. OFF-BALANCE-SHEET ARRANGEMENTS In the course of its business activities, Occidental pursues a number of projects and transactions to meet its core business objectives. The accounting and financial statement treatment of these transactions is a result of the varying methods of funding employed. Occidental also makes commitments on behalf of unconsolidated entities. These transactions, or groups of transactions, are recorded in compliance with generally accepted accounting principles and, unless otherwise noted, are not reflected on Occidental's balance sheets. The following is a description of the business purpose and nature of these transactions. DOLPHIN PROJECT See discussion of the Dolphin Project in the "Business Review - Oil and Gas, Middle East" section of the MD&A above. ECUADOR In Ecuador, Occidental has a 14-percent interest in the OCP oil export pipeline. In the second half of 2003, the increased production from the Eden-Yuturi oil field in the southeastern corner of Block 15 coincided with the completion of the pipeline. Occidental made capital contributions of $64 million in 2003 and as of December 31, 2003, has contributed a total of $73 million to the project. Occidental reports this investment in its consolidated statements using the equity method of accounting. The project was funded in part by senior project debt. The senior project debt is to be repaid with the proceeds of ship-or-pay tariffs of certain upstream producers in Ecuador, including Occidental. Under their ship-or-pay commitments, Occidental and the other upstream producers have each assumed their respective share of project-specific risks, including operating risk and force-majeure risk. Occidental would be required to make an advance tariff payment in the event of prolonged force majeure, upstream expropriation events, bankruptcy of the pipeline company or its parent company, abandonment of the project, termination of an investment guarantee agreement with Ecuador, or certain defaults by Occidental. This advance tariff would be used by the pipeline company to service or prepay project debt. Occidental's obligation relating to the pipeline company's senior project debt totaled $108 million, and Occidental's obligations relating to performance bonds totaled $14 million at December 31, 2003. As Occidental ships product using the pipeline, its overall obligations will decrease with the reduction of the pipeline company's senior project debt. ELK HILLS POWER Occidental has a 50-percent interest in Elk Hills Power LLC (EHP), a limited liability company that operates a gas-fired, power-generation plant in California. EHP is a variable-interest entity (VIE) under the provisions of FIN 46. Occidental has concluded it is not the primary beneficiary of EHP and, therefore, accounts for this investment using the equity method. In January 2002, EHP entered into a $400 million construction loan facility, which was amended in May 2003 to increase the facility to $425 million. Upon construction completion on July 17, 2003, the facility converted to a $415 million term loan, 50 percent of which is guaranteed by Occidental. 19 RECEIVABLES SALE PROGRAM Occidental has an agreement in place to sell, under a revolving sale program, an undivided interest in a designated pool of trade receivables. This program is used by Occidental as a low-cost source of working capital funding. The balance of receivables sold at December 31, 2003 and 2002 was $360 million. This amount is not included in the debt and related trade receivables accounts, respectively, on Occidental's consolidated balance sheets. Receivables must meet certain criteria to qualify for the program. Under this program, Occidental serves as the collection agent with respect to the receivables sold. An interest in new receivables is sold as collections are made from customers. Fees and expenses under this program are included in selling, general and administrative and other operating expenses. The fair value of any retained interests in the receivables sold is not material. The buyers of the receivables are protected against significant risk of loss on their purchase of receivables. Occidental provides for allowances for any doubtful receivables based on its periodic evaluation of such receivables. The provisions for such receivables were not material in the years ended December 31, 2003, 2002 and 2001. The program can terminate upon the occurrence of certain events, which generally are under Occidental's control or relate to bankruptcy. In such an event, alternative funding would have to be arranged, which could result in an increase in debt recorded on the consolidated balance sheet, with a corresponding increase in the accounts receivable balance. The consolidated income statement effect of such an event would not be significant. LEASES Occidental has entered into various operating-lease agreements, mainly for railcars, power plants, manufacturing facilities and office space. The leased assets are used in Occidental's operations where leasing offers advantages of greater operating flexibility and generally costs less than alternative methods of funding that were available at the time financing decisions were made. Lease payments are expensed mainly as cost of sales. See contractual obligation table below. CONTRACTUAL OBLIGATIONS The table below summarizes and cross-references certain contractual obligations that are reflected in the Consolidated Balance Sheets and/or disclosed in the accompanying Notes.
Payments Due by Year ------------------------------------------------- 2005 2007 2009 Contractual to to and Obligations (in millions) Total 2004 2006 2008 thereafter ========================= ========== ========== ========== ========== ========== CONSOLIDATED BALANCE SHEET Long-term debt (Note 6) (a) $ 4,389 $ 476 $ 653 $ 955 $ 2,305 Capital leases (Note 7) 33 1 2 2 28 Other long-term liabilities (b) 658 75 146 102 335 OTHER OBLIGATIONS Operating leases (Note 7) (c) 1,332 106 179 137 910 Purchase obligations (d) 2,728 1,657 292 151 628 ---------- ---------- ---------- ---------- ---------- TOTAL $ 9,140 $ 2,315 $ 1,272 $ 1,347 $ 4,206 ========================= ========== ========== ========== ========== ==========
(a) Includes trust preferred securities reported as current liabilities at December 31, 2003, and excludes fair-value hedge mark-to-market adjustments and unamortized debt discounts. (b) Primarily includes obligations under postretirement benefit and deferred compensation plans. (c) Amounts are presented gross of sublease rental income. (d) Primarily includes long-term purchase contracts and purchase orders and contracts for goods and services used in manufacturing and producing operations in the normal course of business. Some of these arrangements involve take-or-pay commitments but they do not represent debt obligations. Due to their long-term nature, purchase contracts with terms greater than 5 years are discounted using a 6-percent discount rate. LAWSUITS, CLAIMS, COMMITMENTS, CONTINGENCIES AND RELATED MATTERS OPC and certain of its subsidiaries have been named in a substantial number of lawsuits, claims and other legal proceedings. These actions seek, among other things, compensation for alleged personal injury, breach of contract, property damage, punitive damages, civil penalties or other losses; or injunctive or declaratory relief. OPC and certain of its subsidiaries also have been named in proceedings under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) and similar federal, state and local environmental laws. These environmental proceedings seek funding or performance of remediation and, in some cases, compensation for alleged property damage, punitive damages and civil penalties; however, Occidental is usually one of many companies in these proceedings and has to date been successful in sharing response costs with other financially sound companies. With respect to all such lawsuits, claims and proceedings, including environmental proceedings, Occidental accrues reserves when it is probable a liability has been incurred and the amount of loss can be reasonably estimated. 20 During the course of its operations, Occidental is subject to audit by tax authorities for varying periods in various federal, state, local and foreign tax jurisdictions. Taxable years prior to 1997 are closed for U.S. federal income tax purposes. Taxable years 1997 through 2002 are in various stages of audit by the Internal Revenue Service. Disputes arise during the course of such audits as to facts and matters of law. Occidental has entered into agreements providing for future payments to secure terminal and pipeline capacity, drilling services, electrical power, steam and certain chemical raw materials. At December 31, 2003, the net present value of the fixed and determinable portion of the obligations under these agreements, which were used to collateralize financings of the respective suppliers, aggregated $45 million, which was payable as follows (in millions): 2004--$12, 2005--$11, 2006--$10, 2007--$9 and 2008--$3. Fixed payments under these agreements were $16 million in 2003, $27 million in 2002 and $20 million in 2001. Occidental has certain other commitments under contracts, guarantees and joint ventures, and certain other contingent liabilities. Many of these commitments, although not fixed or determinable, involve capital expenditures and are part of the $1.4 billion capital expenditures estimated for 2004, and the $250 to $300 million estimated to be spent on the Dolphin Project in 2004. As discussed under "Significant Accounting Changes" below, FIN 45 requires the disclosure in Occidental's financial statements of information relating to guarantees issued by Occidental and outstanding at December 31, 2003. These guarantees encompass performance bonds, letters of credit, indemnities, commitments and other forms of guarantees provided by Occidental to third parties, mainly to provide assurance that Occidental and/or its subsidiaries and affiliates will meet their various obligations (guarantees). At December 31, 2003, the notional amount of the guarantees was approximately $500 million. Of this amount, approximately $400 million relates to Occidental's guarantee of equity investees' debt and other commitments. The debt guarantees relating to Elk Hills Power and the guarantees on debt and other commitments relating to the Ecuador pipeline have been discussed above in the "Off-Balance-Sheet Arrangements" section. The remaining $100 million relates to various indemnities and guarantees provided to third parties. Occidental has indemnified various parties against specified liabilities that those parties might incur in the future in connection with purchases and other transactions that they have entered into with Occidental. These indemnities usually are contingent upon the other party incurring liabilities that reach specified thresholds. As of December 31, 2003, Occidental is not aware of circumstances that would lead to future indemnity claims against it for material amounts in connection with these transactions. It is impossible at this time to determine the ultimate liabilities that OPC and its subsidiaries may incur resulting from any lawsuits, claims and proceedings, audits, commitments, contingencies and related matters. If these matters were to be ultimately resolved unfavorably at amounts substantially exceeding Occidental's reserves, an outcome not currently anticipated, it is possible that such outcome could have a material adverse effect upon Occidental's consolidated financial position or results of operations. However, after taking into account reserves, management does not expect the ultimate resolution of any of these matters to have a material adverse effect upon Occidental's consolidated financial position or results of operations. ENVIRONMENTAL LIABILITIES AND EXPENDITURES Occidental's operations in the United States are subject to stringent federal, state and local laws and regulations relating to improving or maintaining environmental quality. Foreign operations also are subject to environmental-protection laws. Costs associated with environmental compliance have increased over time and are generally expected to rise in the future. Environmental expenditures related to current operations are factored into the overall business planning process. These expenditures are mainly considered an integral part of production in manufacturing quality products responsive to market demand. ENVIRONMENTAL REMEDIATION The laws that require or address environmental remediation may apply retroactively to past waste disposal practices and releases. In many cases, the laws apply regardless of fault, legality of the original activities or current ownership or control of sites. OPC or certain of its subsidiaries are currently participating in environmental assessments and cleanups under these laws at federal Superfund sites, comparable state sites and other remediation sites, including Occidental facilities and previously owned sites. Also, OPC and certain of its subsidiaries have been involved in a substantial number of governmental and private proceedings involving historical practices at various sites including, in some instances, having been named in proceedings under CERCLA and similar federal, state and local environmental laws. These proceedings seek funding or performance of remediation and, in some cases, compensation for alleged property damage, punitive damages and civil penalties. Occidental manages its environmental remediation efforts through a wholly owned subsidiary, Glenn Springs Holdings, Inc. (GSH), which reports its results directly to Occidental's corporate management. 21 The following table presents Occidental's environmental remediation reserves at December 31, 2003, 2002 and 2001 grouped by three categories of environmental remediation sites:
$ amounts in millions 2003 2002 2001 ===================== =============== =============== =============== # OF RESERVE # of Reserve # of Reserve SITES BALANCE Sites Balance Sites Balance ----- ------- ----- ------- ----- ------- CERCLA & equivalent sites 131 $ 240 124 $ 284 126 $ 320 Active facilities 13 79 14 46 14 59 Closed or sold facilities 39 53 44 63 47 75 ----- ------- ----- ------- ----- ------- TOTAL 183 $ 372 182 $ 393 187 $ 454 ===================== ===== ======= ===== ======= ===== =======
The increase in the number of CERCLA and equivalent sites between 2002 and 2003 was primarily in the "minimal/no exposure" category as discussed below. The following table shows environmental reserve activity for the past three reporting periods:
In millions 2003 2002 2001 ============================ ======== ======== ======== Balance - Beginning of Year $ 393 $ 454 $ 402 Increases to provision including interest accretion 64 25 111 Changes from acquisitions/dispositions -- -- 5 Payments (83) (84) (75) Other (2) (2) 11 -------- -------- -------- Balance - End of Year $ 372 $ 393 $ 454 ============================ ======== ======== ========
Occidental expects to expend funds equivalent to about half of the current environmental reserve over the next three years and the balance over the next ten or more years. Occidental expects that it may continue to incur additional liabilities beyond those recorded for environmental remediation at these and other sites. The range of reasonably possible loss for existing environmental remediation matters could be up to $400 million beyond the amount accrued. For management's opinion, refer to the "Lawsuits, Claims, Commitments, Contingencies and Related Matters" section above. CERCLA AND EQUIVALENT SITES At December 31, 2003, OPC or certain of its subsidiaries have been named in 131 CERCLA or state equivalent proceedings, as shown below.
Reserve Description ($ amounts in millions) # of Sites Balance =================================== ============ =========== Minimal/No exposure (a) 109 $ 5 Reserves between $1-10 MM 15 59 Reserves over $10 MM 7 176 ------------ ----------- TOTAL 131 $ 240 =================================== ============ ===========
(a) Includes 33 sites for which Maxus Energy Corporation has retained the liability and indemnified Occidental, 7 sites where Occidental has denied liability without challenge, 57 sites where Occidental's reserves are less than $50,000 each, and 12 sites where reserves are between $50,000 and $1 million each. The seven sites with individual reserves over $10 million in 2003 are a former copper mining and smelting operation in Tennessee, two closed landfills in Western New York, groundwater treatment facilities at three former chemical plants (Western New York, Montague, Michigan and Tacoma, Washington) and a municipal drinking water treatment plant in Western New York. ACTIVE FACILITIES Certain subsidiaries of OPC are currently addressing releases of substances from past operations at 13 active facilities. Four facilities -- certain oil and gas properties in the southwestern United States, a chemical plant in Louisiana, a chemical plant in Texas, and a phosphorous recovery operation in Tennessee -- account for 89 percent of the reserves associated with these facilities. CLOSED OR SOLD FACILITIES There are 39 sites formerly owned or operated by certain subsidiaries of OPC that have ongoing environmental remediation requirements. Three sites account for 72 percent of the reserves associated with this group. The three sites are: an active refinery in Louisiana where Occidental indemnifies the current owner and operator for certain remedial actions, a water treatment facility at a former coal mine in Pennsylvania, and a former chemical plant in West Virginia. ENVIRONMENTAL COSTS Occidental's costs, some of which may include estimates, relating to compliance with environmental laws and regulations, are shown below for each segment:
In millions 2003 2002 2001 ============================= ======== ======== ======== OPERATING EXPENSES Oil and Gas $ 40 $ 32 $ 22 Chemical 49 46 47 -------- -------- -------- $ 89 $ 78 $ 69 ======== ======== ======== CAPITAL EXPENDITURES Oil and Gas $ 98 $ 70 $ 60 Chemical 15 16 20 -------- -------- -------- $ 113 $ 86 $ 80 ======== ======== ======== REMEDIATION EXPENSES Corporate $ 63 $ 23 $ 109 ============================= ======== ======== ========
Operating expenses are incurred on a continual basis. Capital expenditures relate to longer-lived improvements in currently operating facilities. Remediation expenses relate to existing conditions caused by past operations and do not contribute to current or future revenue generation. Although total costs may vary in any one year, over the long term, segment operating and capital expenditures for environmental compliance generally are expected to increase. 22 In October 2001, the federal Environmental Protection Agency (EPA) approved a State Implementation Plan (SIP) for eight counties in the Houston-Galveston area of Texas to implement certain requirements of the federal Clean Air Act. The SIP contains provisions requiring the reduction of 80 percent of nitrogen oxide emissions and 60 percent of certain volatile organic compound emissions by November 2007. Occidental operates six facilities that are subject to the SIP's emissions reduction requirements and estimates that its future capital expenditures will total approximately $25 to $30 million for environmental control and monitoring equipment necessary to comply with the SIP. Occidental expects expenditures to end in 2007, although the timing of the expenditures will vary by facility. Occidental presently estimates that capital expenditures for environmental compliance (including the SIP discussed above) will be approximately $82 million for 2004 and $97 million for 2005. FOREIGN INVESTMENTS Portions of Occidental's assets outside North America are exposed to political and economic risks. Occidental conducts its financial affairs so as to mitigate its exposure against those risks. At December 31, 2003, the carrying value of Occidental's assets in countries outside North America aggregated approximately $3.3 billion, or approximately 18 percent of Occidental's total assets at that date. Of such assets, approximately $2.3 billion are located in the Middle East, approximately $759 million are located in Latin America, and substantially all of the remainder are located in Pakistan. CRITICAL ACCOUNTING POLICIES AND ESTIMATES The process of preparing financial statements in accordance with GAAP requires the management of Occidental to make estimates and judgments regarding certain items and transactions. It is possible that materially different amounts could be recorded if these estimates and judgments change or if the actual results differ from these estimates and judgments. Occidental considers the following to be its most critical accounting policies and estimates that involve the judgment of Occidental's management. There has been no material change to these policies over the past three years. The selection and development of these critical accounting policies and estimates have been discussed with the Audit Committee of the Board of Directors. OIL AND GAS PROPERTIES Occidental uses the successful efforts method to account for its oil and gas properties. Under this method, costs of acquiring properties, costs of drilling successful exploration wells and development costs are capitalized. Annual lease rentals, exploration costs, geological, geophysical and seismic costs and exploratory dry-hole costs are expensed as incurred. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids (NGLs) that geological and engineering data demonstrate with reasonable certainty can be recovered in future years from known reservoirs under existing economic and operating conditions considering future production and development costs. There are several factors that could change Occidental's recorded oil and gas reserves. Occidental receives a share of production from production-sharing contracts to recover its costs and an additional share for profit. Occidental's share of production from these contracts decreases when oil prices improve and increases when oil prices decline. Overall, Occidental's net economic benefit from these contracts is greater at higher oil prices. In other contractual arrangements, sustained lower product prices may lead to a situation where production of proved reserves becomes uneconomical. Estimation of future production and development costs is also subject to change partially due to factors beyond Occidental's control, such as energy costs and inflation or deflation of oil field service costs. These factors, in turn, could lead to a reduction in the quantity of recorded proved reserves. An additional factor that could result in a change of proved reserves is the reservoir decline rates being different from those assumed when the reserves were initially recorded. Overall, Occidental's revisions to proved reserves were positive for 2003, 2002 and 2001 and amounted to less than 1 percent of the total reserves for each year. Additionally, Occidental is required to perform impairment tests pursuant to SFAS No. 144 generally when prices decline and/or reserve estimates change significantly. There have been no impairments of reserves over the past three years. Depreciation and depletion of oil and gas producing properties is determined by the unit-of-production method and could change with revisions to estimated proved recoverable reserves. The change in the depreciation and depletion rate over the past three years due to revisions of previous reserve estimates has been immaterial. If Occidental's oil and gas reserves were to change based on the factors mentioned above, the most significant impact would be on the depreciation and depletion rate. For example, a 5-percent increase in the amount of oil and gas reserves would change the rate from $4.82/barrel to $4.58/barrel, which would increase pre-tax income by $48 million annually. A 5-percent decrease in the oil and gas reserves would change the rate from $4.82/barrel to $5.06/barrel and would result in a decrease in pre-tax income of $48 million annually. A portion of the carrying value of Occidental's oil and gas properties is attributable to unproved properties. At December 31, 2003, the costs attributable to unproved properties were approximately $900 million. These costs are not currently being depreciated or depleted. As exploration and development work progresses and the reserves on these properties are proven, capitalized 23 costs attributable to the properties will be subject to depreciation and depletion. If the exploration and development work were to be unsuccessful, the capitalized costs of the properties related to this unsuccessful work would be expensed in the year in which the determination was made. The timing of any writedowns of these unproven properties, if warranted, depends upon the nature, timing and extent of future exploration and development activities and their results. Occidental believes its exploration and development efforts will allow it to realize the unproved property balance. CHEMICAL ASSETS The most critical accounting policy affecting Occidental's chemical assets is the determination of the estimated useful lives of its property, plant and equipment. Occidental's chemical plants are depreciated using either the unit-of-production or straight-line method based upon the estimated useful life of the facilities. The estimated useful lives of Occidental's chemical assets, which range from 3 years to 50 years, are used to compute depreciation expense and are also used for impairment tests. The estimated useful lives used for the chemical facilities are based on the assumption that Occidental will provide an appropriate level of annual expenditures to maintain the facilities in good operating condition. Without these continued expenditures, the useful lives of these plants could significantly decrease. Other factors that could change the estimated useful lives of Occidental's chemical plants include higher or lower product prices, which are particularly affected by both domestic and foreign competition, feedstock costs, energy prices, environmental regulations, competition and technological changes. Occidental is required to perform impairment tests on its assets whenever events or changes in circumstances lead to a reduction in the estimated useful lives or estimated future cash flows that would indicate that the carrying amount may not be recoverable, or when management's plans change with respect to those assets. Under the provisions of SFAS No. 144, Occidental must compare the undiscounted future cash flows of an asset to its carrying value. The key factors that could significantly affect future cash flows are future product prices, which are particularly affected by both domestic and foreign competition, feedstock costs, energy costs, significantly increased regulation and remaining estimated useful life. Due to a temporary decrease in demand for some of its products, Occidental temporarily idled an EDC plant in June 2001, a chlor-alkali plant in December 2001 and a portion of a chlor-alkali plant in June 2003. These facilities will remain idle until market conditions improve. Management expects that these plants will become operational in the future. The net book value of these plants was $156 million at December 31, 2003. Based on year-end value, the chlor-alkali plant that closed on December 1, 2001 has a 24-percent minority interest of $28 million. These facilities are periodically tested for impairment and, based on the results, no impairment is deemed necessary at this time. Occidental continues to depreciate these facilities based on their remaining estimated useful lives. Over the prior three years, the change in the depreciation rate due to changes in estimated useful lives has been immaterial. Occidental's net property, plant and equipment for chemicals is approximately $2.6 billion and its annual depreciation expense is expected to be approximately $225 million. If the estimated useful lives of Occidental's chemical plants were to decrease based on the factors mentioned above, the most significant impact would be on depreciation expense. For example, a reduction in the remaining useful lives of 20 percent would increase depreciation and reduce pre-tax earnings by approximately $50 million per year. ENVIRONMENTAL LIABILITIES AND EXPENDITURES Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Reserves for estimated costs that relate to existing conditions caused by past operations and that do not contribute to current or future revenue generation are recorded when environmental remedial efforts are probable and the costs can be reasonably estimated. In determining the reserves and the reasonably possible range of loss, Occidental refers to currently available information, including relevant past experience, available technology, regulations in effect, the timing of remediation and cost-sharing arrangements. The environmental reserves are based on management's estimate of the most likely cost to be incurred and are reviewed periodically and adjusted as additional or new information becomes available. For the years ended December 31, 2003 and 2002, Occidental has not accrued any reimbursements or indemnification recoveries for environmental remediation matters as assets. Recoveries and reimbursements are recorded in income when receipt is probable. Environmental reserves are recorded on a discounted basis only when a reserve is initially established and the aggregate amount of the estimated costs for a specific site and the timing of cash payments are reliably determinable. The reserve methodology for a specific site is not modified once it has been established. Many factors could result in changes to Occidental's environmental reserves and reasonably possible range of loss. The most significant are: >> The original cost estimate may have been inaccurate. >> Modified remedial measures might be necessary to achieve the required remediation results. Occidental generally assumes that the remedial objective can be achieved using the most cost-effective technology reasonably expected to achieve that objective. Such technologies may include air sparging or phyto-remediation of shallow groundwater, or limited surface soil removal or in-situ treatment producing acceptable risk assessment results. Should such remedies fail to achieve remedial objectives, more intensive or costly measures may be required. 24 >> The remedial measure might take more or less time than originally anticipated to achieve the required contaminant reduction. Site-specific time estimates can be affected by factors such as groundwater capture rates, anomalies in subsurface geology, interactions between or among water-bearing zones and non-water-bearing zones, or the ability to identify and control contaminant sources. >> The regulatory agency might ultimately reject or modify Occidental's proposed remedial plan and insist upon a different course of action. Additionally, other events might occur that could affect Occidental's future remediation costs, such as: >> The discovery of more extensive contamination than had been originally anticipated. For some sites with impacted groundwater, accurate definition of contaminant plumes requires years of monitoring data and computer modeling. Migration of contaminants may follow unexpected pathways along geologic anomalies that could initially go undetected. Additionally, the size of the area requiring remediation may change based upon risk assessment results following site characterization or interim remedial measures. >> Improved remediation technology might decrease the cost of remediation. In particular, for groundwater remediation sites with projected long-term operation and maintenance, the development of more effective treatment technology, or acceptance of alternative and more cost-effective treatment methodologies such as bio-remediation, could significantly affect remediation costs. >> Laws and regulations might change to impose more or less stringent remediation requirements. At sites involving multiple parties, Occidental provides environmental reserves based upon its expected share of liability. When other parties are jointly liable, the financial viability of the parties, the degree of their commitment to participate and the consequences to Occidental of their failure to participate are evaluated when estimating Occidental's ultimate share of liability. Based on these factors, Occidental believes that it will not be required to assume a share of liability of other potentially responsible parties, with whom it is alleged to be jointly liable, in an amount that would have a material effect on Occidental's consolidated financial position, liquidity or results of operations. Most cost sharing arrangements with other parties fall into one of the following three categories: Category 1: CERCLA or state-equivalent sites wherein Occidental and other alleged potentially responsible parties share the cost of remediation in accordance with negotiated or prescribed allocations; Category 2: Oil and gas joint ventures wherein each joint venture partner pays its proportionate share of remedial cost; and Category 3: Contractual arrangements typically relating to purchases and sales of property wherein the parties to the transaction agree to methods of allocating the costs of environmental remediation. In all three of these categories, Occidental records as a reserve its expected net cost of remedial activities, as adjusted by recognition for any non-performing parties. In addition to the costs of investigating and implementing remedial measures, which often take in excess of ten years at CERCLA sites, Occidental's reserves include management's estimates of the cost of operation and maintenance of remedial systems. To the extent that the remedial systems are modified over time in response to significant changes in site-specific data, laws, regulations, technologies or engineering estimates, Occidental reviews and changes the reserves accordingly on a site-specific basis. If the environmental reserve balance were to either increase or decrease based on the factors mentioned above, the amount of the increase or decrease would be immediately recognized in earnings. For example, if the reserve balance were to decrease by 10 percent, Occidental would record a pre-tax gain of $37 million. If the reserve balance were to increase by 10 percent, Occidental would record an additional remediation expense of $37 million. OTHER LOSS CONTINGENCIES Occidental is involved with numerous lawsuits, claims, proceedings and audits in the normal course of its operations. Occidental records a loss contingency for these matters when it is probable that an asset has been impaired or a liability has been incurred and the amount of the loss can be reasonably estimated. In addition, Occidental discloses, in aggregate, its exposure to loss in excess of the amount recorded on the balance sheet for these matters if it is reasonably possible that an additional material loss may be incurred. Occidental reviews its loss contingencies on an on-going basis so that they are adequately reserved on the balance sheet. These reserves are based on judgments made by management with respect to the likely outcome of these matters and are adjusted as appropriate. Management's judgments could change based on new information, changes in laws or regulations, changes in management's plans or intentions, the outcome of legal proceedings, settlements or other factors. SIGNIFICANT ACCOUNTING CHANGES Listed below are significant changes in Occidental's accounting principles. SFAS NO. 132 REVISED In December 2003, the FASB issued a revision to SFAS No. 132, "Employers Disclosures about Pensions and Other Postretirement Benefits" to improve financial statement disclosures for defined benefit plans. The standard requires that companies provide more details about their plan assets, benefit obligations, cash flows and other relevant information, such as plan assets by category. A description of investment policies and strategies for these asset categories and target allocation percentages or target ranges are also required 25 in financial statements. This statement is effective for financial statements with fiscal years ending after December 15, 2003. Occidental adopted this statement in the fourth quarter of 2003 and provided the required disclosure in this report. SFAS NO. 150 In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity." SFAS No. 150 establishes accounting standards for how a company classifies and measures financial instruments that have characteristics of liabilities and equity. Occidental adopted the provisions of this statement on July 1, 2003. As a result of the adoption, Occidental's mandatorily redeemable trust preferred securities are now classified as a liability and the payments to the holders of the securities, which were previously recorded as minority interest on the statement of operations, are recorded as interest expense. On January 20, 2004, all of the trust preferred securities were redeemed. SFAS NO. 149 In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities." SFAS No. 149 amends and clarifies financial accounting and reporting for derivative instruments. This statement is effective for contracts entered into or modified after June 30, 2003. Occidental adopted this statement in the third quarter of 2003 and it did not have a material effect on its financial statements. FIN 46 AND FIN 46-R (REVISED) In January 2003, the FASB issued FIN 46, "Consolidation of Variable Interest Entities." FIN 46 requires a company to consolidate a VIE if it is designated as the primary beneficiary of that entity even if the company does not have a majority of voting interests. A VIE is generally defined as an entity whose equity is unable to finance its activities or whose owners lack the risks and rewards of ownership. The statement also imposes disclosure requirements for all the VIEs of a company, even if the company is not the primary beneficiary. The provisions of this statement apply at inception for any entity created after January 31, 2003. Occidental adopted the provisions of this Interpretation for its existing entities on April 1, 2003, which resulted in the consolidation of its OxyMar investment. As a result of the OxyMar consolidation, assets increased by $166 million and liabilities increased by $178 million. There was no material effect on net income as a result of the consolidation. In September 2003, Marubeni indicated it would exercise its option to put its interest in OxyMar to Occidental by paying approximately $25 million to Occidental. In connection with the transfer, which is expected to be complete in April 2004, Occidental will assume Marubeni's guarantee of OxyMar's debt. As all the OxyMar debt is already consolidated in Occidental's financial statements with the adoption of FIN 46, the exercise of the put will not have a material effect on Occidental's financial position or results of operations. See "Off-Balance-Sheet Arrangements - Elk Hills Power" for information on VIEs where Occidental is not the primary beneficiary. In December 2003, the FASB revised FIN 46 to exempt certain entities from its requirements and to clarify certain issues arising during the initial implementation of FIN 46. Occidental will adopt the revised interpretation in the first quarter of 2004 and it is not expected to have an impact on the financial statements when adopted. FIN 45 In January 2003, the FASB issued FIN 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others." FIN 45 requires a company to recognize a liability for the obligations it has undertaken in issuing a guarantee. This liability would be recorded at the inception of a guarantee and would be measured at fair value. FIN 45 also requires certain disclosures related to guarantees, which are included in Note 9. Occidental adopted the measurement provisions of this statement in the first quarter of 2003 and it did not have an effect on the financial statements when adopted. EITF ISSUE NO. 02-3 In the third quarter of 2002, Occidental adopted certain provisions of Emerging Issues Task Force (EITF) Issue No. 02-3, "Issues involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities." These provisions prescribed significant changes in how revenue from energy trading is recorded. Historically, Occidental had two major types of oil and gas revenues: (1) revenues from its equity production; and (2) revenues from the sale of oil and gas produced by other companies, but purchased and resold by Occidental, referred to as revenue from trading activities. Both types of sales involve physical deliveries and had been historically recorded on a gross basis in accordance with generally accepted accounting principles. With the adoption of EITF Issue No. 02-3, Occidental now reflects the revenue from trading activities on a net basis. There were no changes in gross margins, net income, cash flow or earnings per share for any period as a result of adopting this requirement. However, net sales and cost of sales were reduced by equal and offsetting amounts to reflect the adoption of this requirement. For the years ended December 31, 2002 and 2001, net sales and cost of sales were reduced from amounts previously reported by approximately $2.2 billion (representing amounts for the first two quarters of 2002) and $5.8 billion, respectively, to conform to the current presentation. Since 1999, Occidental has accounted for certain energy-trading contracts in accordance with EITF Issue No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities." EITF Issue No. 98-10 required that all energy-trading contracts must be marked to fair value with gains and losses included in earnings, whether the contracts were derivatives or not. 26 In October 2002, the EITF rescinded EITF Issue No. 98-10 thus precluding mark-to-market accounting for all energy-trading contracts that are not derivatives and fair value accounting for inventories purchased from third parties. Also, the rescission requires derivative gains and losses to be presented net on the income statement, whether or not they are physically settled, if the derivative instruments are held for trading purposes. Occidental adopted this accounting change in the first quarter of 2003 and recorded a cumulative effect of a change in accounting principles charge of approximately $18 million, after tax. SFAS NO. 146 In July 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities." SFAS No. 146 requires that a liability be recognized for exit and disposal costs only when the liability has been incurred and when it can be measured at fair value. The statement is effective for exit and disposal activities that are initiated after December 31, 2002. Occidental adopted SFAS No. 146 in the first quarter of 2003 and it did not have a material effect on its financial statements. SFAS NO. 145 In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections." In addition to amending or rescinding other existing authoritative pronouncements to make various technical corrections, clarify meanings, or describe their applicability under changed conditions, SFAS No. 145 precludes companies from recording gains and losses from the extinguishment of debt as an extraordinary item. Occidental implemented SFAS No. 145 in the fourth quarter of 2002 and all comparative financial statements have been reclassified to conform to the 2002 presentation. Since Occidental had no 2002 extraordinary items, there was no effect on the 2002 presentation. The effects of the statement on prior years include the reclassification of an extraordinary loss to net income from continuing operations of $8 million ($0.02 per share) in 2001. There was no effect on net income or basic earnings per common share upon adoption. SFAS NO. 143 In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. Under SFAS No. 143, companies are required to recognize the fair value of a liability for an asset retirement obligation in the period in which the liability is incurred if there is a legal obligation to dismantle the asset and reclaim or remediate the property at the end of the useful life. Occidental adopted SFAS No. 143 in the first quarter of 2003. The initial adoption resulted in an after-tax charge of $50 million, which was recorded as a cumulative effect of a change in accounting principles. The adoption increased net property, plant and equipment by $73 million, increased asset retirement obligations by $151 million and decreased deferred tax liabilities by $28 million. The pro-forma asset retirement obligation, if the adoption of this statement had occurred on January 1, 2002, would have been $131 million at January 1, 2002 and $151 million at December 31, 2002. SFAS NO. 142 In June 2001, the FASB issued SFAS No. 142, "Goodwill and Other Intangible Assets." SFAS No. 142 changes the accounting and reporting requirements for acquired goodwill and intangible assets. The provisions of this statement are applied to companies starting with fiscal years beginning after December 15, 2001. At December 31, 2001, the balance sheet included approximately $108 million of goodwill and intangible assets with annual amortization expense of approximately $6 million recorded in each of the years' income statements for the three-year period ended December 31, 2001. As a result, elimination of goodwill amortization would not have had a material impact on net income or earnings per share of any of the years presented and, as a result, the transitional disclosures of adjusted net income excluding goodwill amortization described by SFAS No. 142 have not been presented. Upon implementation of SFAS No. 142 in the first quarter of 2002, three separate specialty chemical businesses were identified as separate reporting units and tested for goodwill impairment. All three of these businesses are components of the chemical segment. The fair value of each of the three reporting units was determined through third party appraisals. The appraisals determined fair value to be the price that the assets could be sold for in a current transaction between willing parties. As a result of the impairment testing, Occidental recorded a cumulative effect of changes in accounting principles after-tax reduction in net income of approximately $95 million due to the impairment of all the goodwill attributed to these reporting units. SFAS NO. 133 On January 1, 2001, Occidental adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended. This statement established accounting and reporting standards for derivative instruments and hedging activities and required an entity to recognize derivatives on the balance sheet and measure those instruments at fair value. Changes in the derivative instrument's fair value must be recognized in earnings unless specific hedge accounting criteria are met. Adoption of this new accounting standard resulted in cumulative after-tax reductions in net income of approximately $24 million and Other Comprehensive Income (OCI) of approximately $27 million in the first quarter of 2001. The adoption also increased total assets by $588 million and total liabilities by $639 million as of January 1, 2001. 27 INTANGIBLE ASSETS The EITF currently is deliberating on EITF No. 03-O, "Whether Mineral Rights Are Tangible or Intangible Assets" and EITF No. 03-S "Application of FASB Statement No. 142, Goodwill and Other Intangible Assets, to Oil and Gas Companies." These proposed statements will determine whether contract-based oil and gas mineral rights are classified as tangible or intangible assets based on the EITF's interpretation of SFAS No. 141 and SFAS No. 142. Historically, Occidental has classified all of its contract-based mineral rights within property, plant and equipment and has generally not identified these amounts separately. If the EITF determines that these mineral rights should be presented as intangible assets, Occidental would have to reclassify its contract-based oil and gas mineral rights acquired after June 30, 2001 to intangible assets and make additional disclosures in accordance with SFAS No. 142. If Occidental adopted this change, approximately $492 million and $226 million of the property, plant and equipment balance would be reclassified to intangible assets at December 31, 2003 and 2002, respectively. These amounts, which are net of accumulated depreciation, depletion and amortization, include approximately $475 million and $210 million of mineral rights related to proved properties at December 31, 2003 and 2002, respectively. Occidental has been amortizing these amounts under the unit-of-production method and would continue to amortize the mineral rights under this method. Based on its understanding of the scope of the EITF deliberations, Occidental believes the adoption of this potential decision would have no material effect on its results of operations. DERIVATIVE ACTIVITIES AND MARKET RISK GENERAL Occidental's market risk exposures relate primarily to commodity prices and, to a lesser extent, interest rates and foreign currency exchange rates. Occidental periodically enters into derivative instrument transactions to reduce these price and rate fluctuations. A derivative is a financial instrument which derives its value from another instrument or variable. In general, the fair value recorded for derivative instruments is based on quoted market prices, dealer quotes and the Black-Scholes or similar valuation models. ACCOUNTING FOR DERIVATIVES AND DEFINITIONS Occidental applies either fair value or cash flow hedge accounting when transactions meet specified criteria to obtain hedge accounting treatment. If the derivative does not qualify as a hedge or is not designated as a hedge, the gain or loss is immediately recognized in earnings. If the derivative qualifies for hedge accounting, the gain or loss on the derivative is either recognized in income with an offsetting adjustment to the basis of the item being hedged for fair value hedges, or deferred in OCI to the extent the hedge is effective for cash flow hedges. A hedge is regarded as highly effective and qualifies for hedge accounting if, at inception and throughout its life, it is expected that changes in the fair value or cash flows of the hedged item are almost fully offset by the changes in the fair value or changes in cash flows of the hedging instrument and actual effectiveness is within a range of 80 percent to 125 percent. In the case of hedging a forecasted transaction, the transaction must be highly probable and must present an exposure to variations in cash flows that could ultimately affect reported net profit or loss. Occidental discontinues hedge accounting when it is determined that a derivative has ceased to be highly effective as a hedge; when the derivative expires, or is sold, terminated, or exercised; when the hedged item matures or is sold or repaid; or when a forecasted transaction is no longer deemed highly probable. COMMODITY PRICE RISK GENERAL Occidental's results are sensitive to fluctuations in crude oil and natural gas prices. Based on current levels of production, if oil prices vary overall by $1 per barrel, it would have approximately a $125 million annual effect on income before U.S. income tax. If natural gas prices vary by $0.25 per MCF, it would have approximately a $48 million annual effect on income before U.S. income tax. If production levels change in the future, the sensitivity of Occidental's results to oil and gas prices also would change. Occidental's results are also sensitive to fluctuations in chemical prices. If chlorine and caustic soda prices vary by $10/ton, it would have approximately a $12 million and $25 million, respectively, annual effect on income before U.S. income taxes. If PVC prices vary by $.01/lb, it would have approximately a $27 million annual effect on income before U.S. income taxes. If EDC prices vary by $10/ton, it would have approximately a $3 million annual effect on income before U.S. income taxes. Historically, price changes either precede or follow raw material and feedstock price changes; therefore, the margin improvement of price changes can be mitigated. According to Chemical Market Associates, Inc., December 2003 average contract prices were: chlorine--$203/ton, caustic soda--$133/ton, PVC--$0.44/lb and EDC--$228/ton. MARKETING AND TRADING OPERATIONS Occidental periodically uses different types of derivative instruments to achieve the best prices for oil and gas. Derivatives are also used by Occidental to reduce its exposure to price volatility and mitigate fluctuations in commodity-related cash flows. Occidental enters into low-risk marketing and trading activities through its separate marketing organization, which operates under established policy controls and procedures. With respect to derivatives used in its oil and gas marketing operations, Occidental utilizes a combination of futures, forwards, options and swaps to offset various physical transactions. Overall, Occidental has a low level of involvement in the hedging of long-term oil and gas prices and its use of derivatives in hedging activity remains at a correspondingly low level. 28 In September 2002, Occidental unwound its natural gas delivery commitment and corresponding natural gas price swap which were entered into in November 1998. Occidental recognized a pre-tax loss of $3 million related to these transactions. RISK MANAGEMENT Occidental conducts its risk management activities for energy commodities (which include buying, selling, marketing, trading, and hedging activities) under the controls and governance of its Risk Management Policy. The Chief Financial Officer and Risk Management Committee, comprising members of Occidental's management, oversee these controls, which are implemented and enforced by the Trading Control Officer. The Trading Control Officer provides an independent and separate check on results of marketing and trading activities. Controls for energy commodities include limits on credit, limits on trading, segregation of duties, delegation of authority and a number of other policy and procedural controls. FAIR VALUE OF CONTRACTS The following tables reconcile the changes in the fair value of Occidental's marketing and trading contracts during 2003 and 2002 and segregate the open contracts at December 31, 2003 by maturity periods.
In millions 2003 2002 (a) ========================================================== ======== ======== Fair value of contracts outstanding at beginning of year $ (2) $ 43 Losses(gains) on changes on contracts realized or otherwise settled during the year 50 (17) Changes in fair value attributable to changes in valuation techniques and assumptions -- -- (Gains)losses on other changes in fair values (16) (28) -------- -------- Fair value of contracts outstanding at end of year $ 32 $ (2) ========================================================== ======== ========
(a) Amounts have been reclassified to conform to current presentation.
Maturity Periods ------------------------------------------------- 2005 2007 2009 Total Source of to to and Fair Fair Value 2004 2006 2008 thereafter Value ================ ========== ========== ========== ========== ========== Prices actively quoted $ 13 $ 6 $ -- $ -- $ 19 Prices provided by other external sources 7 2 4 3 16 Prices based on models and other valuation methods (3) -- -- -- (3) ---------- ---------- ---------- ---------- ---------- TOTAL $ 17 $ 8 $ 4 $ 3 $ 32 ================ ========== ========== ========== ========== ==========
The tables above include the fair value of physical positions and the fair value of the related financial instruments for trading and marketing operations. At December 31, 2003 and 2002, the physical positions were a net gain of $10 million and $6 million, respectively. The value of the derivative financial instruments that offset these physical positions are a net gain of $22 million and a net loss of $8 million at December 31, 2003 and 2002, respectively. Gains and losses are netted in the statement of operations. On the balance sheets, except where a right of set-off exists, gains are recognized as assets and losses are recognized as liabilities. COMMODITY HEDGES On a limited basis, Occidental uses cash-flow hedges for the sale of crude oil and natural gas production. Crude oil cash-flow hedges were executed for approximately 20 percent of total U.S. oil production in 2002. Natural gas cash-flow hedges were executed for approximately 7 percent of total U.S. 2002 gas production. Occidental's commodity cash-flow-hedging instruments in 2002 were highly effective. At December 31, 2002, all of these cash-flow hedges had been settled. No fair value hedges were used for oil and gas production during 2003 or 2002 and no cash flow hedges were used for the sale of production in 2003. QUANTITATIVE INFORMATION Occidental uses value at risk to estimate the potential effects of changes in fair values of commodity-based derivatives and commodity contracts used in trading activities. This method determines the maximum potential negative short-term change in fair value with a 95-percent level of confidence. For non-trading activities, there were no material amounts outstanding at December 31, 2003. The value at risk for both oil and natural gas is summarized below: MARKETING AND TRADING VALUE AT RISK
For the years ended December 31, (in millions) 2003 2002 ============================================== ======== ======== Value at Risk - Oil High during the year $ -- $ 1 Low during the year -- -- Average for the year -- 1 Value at Risk - Natural Gas High during the year $ 3 $ 1 Low during the year -- -- Average for the year 1 1 ---------------------------------------------- -------- --------
INTEREST RATE RISK GENERAL Occidental is exposed to risk resulting from changes in interest rates and it enters into various derivative financial instruments to manage interest-rate exposure. Interest-rate swaps, forward locks and futures contracts are entered into periodically as part of Occidental's overall strategy. HEDGING ACTIVITIES Occidental has entered into several interest-rate swaps that qualified for fair-value hedge accounting. These derivatives effectively convert approximately $1.8 billion of fixed-rate debt to variable-rate debt with maturities ranging from 2005 to 2009. 29 Occidental was a party to a series of forward interest-rate locks, which qualified as cash-flow hedges. The hedges were related to the construction of a cogeneration plant leased by Occidental that was completed in December 2002. The remaining loss on the hedges through December 2003 was approximately $21 million after-tax, which is recorded in accumulated OCI and is being recognized in earnings over the lease term of 26 years on a straight-line basis. Certain of Occidental's equity investees have entered into additional derivative instruments that qualified as cash-flow hedges. Occidental reflects its proportionate share of these cash-flow hedges in OCI. TABULAR PRESENTATION OF INTEREST RATE RISK In millions of U.S. dollars, except rates
U.S. Dollar U.S. Dollar Year of Maturity Fixed Rate Variable Rate(a) Grand Total (a) ====================== ============= ============= ============= 2005 $ -- $ 157 $ 157 2006 46 450 496 2007 -- 550 550 2008 10 395 405 2009 -- 276 276 Thereafter 1,914 115 2,029 ------------- ------------- ------------- TOTAL $ 1,970 $ 1,943 $ 3,913 ============= ============= ============= Average interest rate 7.17% 3.21% 5.20% ============= ============= ============= Fair Value $ 2,330 $ 2,160 $ 4,490 ====================== ============= ============= =============
(a) Includes fixed-rate debt with fair-value hedges but excludes $87 million of mark-to-market adjustments related to such hedges and $7 million of unamortized debt discounts. CREDIT RISK Occidental's energy contracts are spread among numerous counterparties. Creditworthiness is reviewed before doing business with a new counterparty and on an ongoing basis. Occidental monitors aggregated counterparty exposure relative to credit limits, and manages credit-enhancement issues. Credit exposure for each customer is monitored for outstanding balances, current month activity, and forward mark-to-market exposure. FOREIGN CURRENCY RISK Several of Occidental's foreign operations are located in countries whose currencies generally depreciate against the U.S. dollar. Typically, effective currency forward markets do not exist for these countries. Therefore, Occidental attempts to manage its exposure primarily by balancing monetary assets and liabilities and maintaining cash positions only at levels necessary for operating purposes. Generally, international crude oil sales are denominated in U.S. dollars. Additionally, all of Occidental's oil and gas foreign entities have the U.S. dollar as the functional currency. However, in one foreign chemical subsidiary where the local currency is the functional currency, Occidental has exposure on U.S. dollar-denominated debt that is not material. At December 31, 2003 and 2002, Occidental had not entered into any foreign currency derivative instruments. The effect of exchange-rate transactions in foreign currencies is included in periodic income. DERIVATIVE AND FAIR VALUE DISCLOSURES The following table shows derivative financial instruments included in the consolidated balance sheets:
Balance at December 31, (in millions) 2003 2002 =============================================== ======== ======== Derivative financial instrument assets (a) Current $ 138 $ 164 Non-current 118 157 -------- -------- $ 256 $ 321 ======== ======== Derivative financial instrument liabilities (a) Current $ 85 $ 115 Non-current 23 23 -------- -------- $ 108 $ 138 =============================================== ======== ========
(a) Amounts include energy-trading contracts. As a result of fair-value hedges, the amount of interest expense recorded in the income statement was lower by approximately $58 million and $45 million for the years ended December 31, 2003 and 2002, respectively. The following table summarizes after-tax derivative activity recorded in OCI:
For the years ended December 31, (in millions) 2003 2002 ================================================= ======== ======== Beginning Balance $ (26) $ (20) Losses from changes in current cash flow hedges (17) (14) Amount reclassified to income 19 8 -------- -------- Ending Balance $ (24) $ (26) ================================================= ======== ========
During the next twelve months, Occidental expects that approximately $3 million of net derivative after-tax losses included in OCI, based on their valuation at December 31, 2003, will be reclassified into earnings when the hedged transactions close. Hedge ineffectiveness did not have a significant impact on earnings for the years ended December 31, 2003 and 2002. SELECTED CASH-FLOW INFORMATION Occidental calculates chemical segment free cash flow as segment income, adding back depreciation, depletion and amortization, and subtracting from that amount total capital expenditures, excluding acquisitions. Occidental believes that free cash flow is useful to investors as an indicator of Occidental's ability to generate positive cash results to service and/or repay debt and generate cash for acquisitions and other investments. Free cash flow does not represent residual cash flow available for discretionary expenditures. Changes in working capital are not reflected in free cash flow, and Occidental has certain non-discretionary obligations, such as debt service, that are not deducted from this measure. In addition, this measure should not be considered in isolation or as a substitute for measures prepared in accordance with GAAP or as a measure of profitability or liquidity. Free cash flow as presented herein may not be comparable to similarly titled measures reported by other companies. There is no comparable segment cash-flow measure available under GAAP. 30 In addition, Occidental discloses cumulative net pre-tax cash flows generated by particular properties, which it believes is an important indicator of cumulative life-to-date performance. There is no comparable property level cash flow measure available under GAAP. Chemical segment free cash flow is calculated as follows:
In millions 2003 ============================================= ======== Segment earnings $ 210 Depreciation, depletion and amortization 205 Capital spending (a) (121) -------- Free Cash Flow (b) $ 294 ============================================= ========
(a) Excludes $180 million for the purchase of a previously leased facility in LaPorte, Texas and $44 million related to the exercise of purchase options for certain leased railcars. (b) Excludes working capital changes. SAFE HARBOR STATEMENT REGARDING OUTLOOK AND OTHER FORWARD-LOOKING DATA Portions of this report, including Items 1 and 2 and the information appearing under the caption "Management's Discussion and Analysis of Financial Condition and Results of Operations," including the information under the sub-caption "2004 Outlook," contain forward-looking statements and involve risks and uncertainties that could significantly affect expected results of operations, liquidity, cash flows and business prospects. Factors that could cause results to differ materially include, but are not limited to: global commodity pricing fluctuations; competitive pricing pressures; higher than expected costs including feedstocks; crude oil and natural gas prices; chemical prices; potential liability for remedial actions under existing or future environmental regulations and litigation; potential liability resulting from pending or future litigation; general domestic and international political conditions; potential disruption or interruption of Occidental's production or manufacturing facilities due to accidents, political events or insurgent activity; potential failure to achieve expected production from existing and future oil and gas development projects; the supply/demand considerations for Occidental's products; any general economic recession or slowdown domestically or internationally; regulatory uncertainties; and not successfully completing, or any material delay of, any development of new fields, expansion, capital expenditure, efficiency improvement project, acquisition or disposition. Forward-looking statements are generally accompanied by words such as "estimate", "project", "predict", "will", "anticipate", "plan", "intend", "believe", "expect" or similar expressions that convey the uncertainty of future events or outcomes. Occidental expressly disclaims any obligation to publicly update or revise any forward-looking statements, whether as a result of new information or otherwise. In light of these risks, uncertainties and assumptions, the forward-looking events discussed might not occur. REPORT OF MANAGEMENT The management of Occidental Petroleum Corporation is responsible for the integrity of the financial data reported by Occidental and its subsidiaries. Fulfilling this responsibility requires the preparation and presentation of consolidated financial statements in accordance with generally accepted accounting principles. Management uses internal accounting controls, corporate-wide policies and procedures and judgment so that such statements reflect fairly Occidental's consolidated financial position, results of operations and cash flows. 31 ITEM 8 FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA REPORT OF INDEPENDENT AUDITORS To the Board of Directors and Stockholders, Occidental Petroleum Corporation: We have audited the consolidated balance sheets of Occidental Petroleum Corporation and its subsidiaries (the Company) as of December 31, 2003 and 2002, and the related consolidated statements of operations, stockholders' equity, comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2003. In connection with our audits of the consolidated financial statements, we also have audited the accompanying financial statement schedule. These consolidated financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedule based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Occidental Petroleum Corporation and its subsidiaries as of December 31, 2003 and 2002, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2003, in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein. As explained in Note 4 to the financial statements, effective January 1, 2003, the Company changed its method of accounting for inventories purchased from third parties and its method of accounting for asset retirement obligations. Effective April 1, 2003, the Company changed its method of accounting for the consolidation of variable interest entities. Effective July 1, 2003, the Company changed its method of accounting for certain financial instruments with characteristics of both liabilities and equity. Effective January 1, 2002, the Company changed its method of accounting for the impairment of goodwill and other intangibles. Effective January 1, 2001, the Company changed its method of accounting for derivative instruments and hedging activities. /s/ KPMG LLP Los Angeles, California February 13, 2004 32
CONSOLIDATED STATEMENTS OF OPERATIONS Occidental Petroleum Corporation In millions, except per-share amounts and Subsidiaries For the years ended December 31, 2003 2002 2001 ====================================================================== ========== ========== ========== REVENUES Net sales $ 9,326 $ 7,338 $ 8,102 Interest, dividends and other income 89 143 223 Gains on disposition of assets, net 32 10 10 ---------- ---------- ---------- 9,447 7,491 8,335 ---------- ---------- ---------- COSTS AND OTHER DEDUCTIONS Cost of sales 3,988 3,385 3,626 Selling, general and administrative and other operating expenses 855 677 668 Depreciation, depletion and amortization 1,177 1,012 965 Environmental remediation 63 23 109 Exploration expense 139 176 184 Interest and debt expense, net 332 295 401 ---------- ---------- ---------- 6,554 5,568 5,953 ---------- ---------- ---------- INCOME BEFORE TAXES AND OTHER ITEMS 2,893 1,923 2,382 Provision for domestic and foreign income and other taxes 1,227 422 556 Minority interest 62 77 143 Loss from equity investments 9 261 504 ---------- ---------- ---------- INCOME FROM CONTINUING OPERATIONS 1,595 1,163 1,179 Discontinued operations, net -- (79) (1) Cumulative effect of changes in accounting principles, net (68) (95) (24) ---------- ---------- ---------- NET INCOME $ 1,527 $ 989 $ 1,154 ========== ========== ========== BASIC EARNINGS PER COMMON SHARE Income from continuing operations $ 4.16 $ 3.09 $ 3.16 Discontinued operations, net -- (0.21) -- Cumulative effect of changes in accounting principles, net (0.18) (0.25) (0.06) ---------- ---------- ---------- BASIC EARNINGS PER COMMON SHARE $ 3.98 $ 2.63 $ 3.10 ========== ========== ========== DILUTED EARNINGS PER COMMON SHARE Income from continuing operations $ 4.11 $ 3.07 $ 3.15 Discontinued operations, net -- (0.21) -- Cumulative effect of changes in accounting principles, net (0.18) (0.25) (0.06) ---------- ---------- ---------- DILUTED EARNINGS PER COMMON SHARE $ 3.93 $ 2.61 $ 3.09 ========== ========== ========== DIVIDENDS PER COMMON SHARE $ 1.04 $ 1.00 $ 1.00 ====================================================================== ========== ========== ==========
The accompanying notes are an integral part of these financial statements. 33
CONSOLIDATED BALANCE SHEETS Occidental Petroleum Corporation In millions, except share amounts and Subsidiaries Assets at December 31, 2003 2002 ===================================================================================== ========== ========== CURRENT ASSETS Cash and cash equivalents $ 683 $ 146 Trade receivables, net of reserves of $24 in 2003 and $28 in 2002 804 608 Receivables from joint ventures, partnerships and other 330 321 Inventories 510 491 Income tax receivable 20 150 Prepaid expenses and other 127 157 ---------- ---------- TOTAL CURRENT ASSETS 2,474 1,873 ---------- ---------- LONG-TERM RECEIVABLES, NET 264 275 ---------- ---------- INVESTMENTS IN UNCONSOLIDATED ENTITIES 1,155 1,056 ---------- ---------- PROPERTY, PLANT AND EQUIPMENT Oil and gas segment, successful efforts method 16,698 15,440 Chemical segment 4,499 3,689 Corporate and other 275 302 ---------- ---------- 21,472 19,431 Accumulated depreciation, depletion and amortization (7,467) (6,395) ---------- ---------- 14,005 13,036 OTHER ASSETS 270 308 ---------- ---------- $ 18,168 $ 16,548 ===================================================================================== ========== ==========
The accompanying notes are an integral part of these financial statements. 34
CONSOLIDATED BALANCE SHEETS Occidental Petroleum Corporation In millions, except share amounts and Subsidiaries Liabilities and Equity at December 31, 2003 2002 ===================================================================================== ========== ========== CURRENT LIABILITIES Current maturities of long-term debt and capital lease liabilities $ 23 $ 206 Accounts payable 909 785 Accrued liabilities 877 914 Dividends payable 101 193 Domestic and foreign income taxes 163 137 Trust preferred securities 453 -- ---------- ---------- TOTAL CURRENT LIABILITIES 2,526 2,235 ---------- ---------- LONG-TERM DEBT, NET OF CURRENT MATURITIES AND UNAMORTIZED DISCOUNT 3,993 3,997 ---------- ---------- TRUST PREFERRED SECURITIES -- 455 ---------- ---------- DEFERRED CREDITS AND OTHER LIABILITIES Deferred and other domestic and foreign income taxes 1,001 982 Other 2,407 2,228 ---------- ---------- 3,408 3,210 ---------- ---------- CONTINGENT LIABILITIES AND COMMITMENTS MINORITY INTEREST 312 333 ---------- ---------- STOCKHOLDERS' EQUITY Nonredeemable preferred stock; $1.00 par value, authorized 50 million shares; outstanding shares: 2003 -- none and 2002 -- none -- -- Common stock, $.20 par value; authorized 500 million shares; outstanding shares: 2003 -- 387,047,948 and 2002 -- 377,860,191 77 75 Additional paid-in capital 4,272 3,967 Retained earnings 3,530 2,303 Accumulated other comprehensive income(loss) 50 (27) ---------- ---------- 7,929 6,318 ---------- ---------- $ 18,168 $ 16,548 ===================================================================================== ========== ==========
The accompanying notes are an integral part of these financial statements. 35
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY Occidental Petroleum Corporation In millions and Subsidiaries Accumulated Additional Other Common Paid-in Retained Comprehensive Stock Capital Earnings Income(Loss) ======================================================= ============= ============= ============= ============= BALANCE, DECEMBER 31, 2000 $ 74 $ 3,743 $ 1,007 $ (50) Net income -- -- 1,154 -- Other comprehensive loss, net of tax -- -- -- (36) Dividends on common stock -- -- (373) -- Issuance of common stock -- 19 -- -- Exercises of options and other, net 1 95 -- -- ------------------------------------------------------- ------------- ------------- ------------- ------------- BALANCE, DECEMBER 31, 2001 $ 75 $ 3,857 $ 1,788 $ (86) Net income -- -- 989 -- Other comprehensive income, net of tax -- -- -- 59 Dividends on common stock -- -- (474) -- Issuance of common stock -- 22 -- -- Exercises of options and other, net -- 88 -- -- ------------------------------------------------------- ------------- ------------- ------------- ------------- BALANCE, DECEMBER 31, 2002 $ 75 $ 3,967 $ 2,303 $ (27) Net income -- -- 1,527 -- Other comprehensive income, net of tax -- -- -- 77 Dividends on common stock -- -- (300) -- Issuance of common stock -- 11 -- -- Exercises of options and other, net 2 294 -- -- ------------------------------------------------------- ------------- ------------- ------------- ------------- BALANCE, DECEMBER 31, 2003 $ 77 $ 4,272 $ 3,530 $ 50 ======================================================= ============= ============= ============= =============
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME In millions For the years ended December 31, 2003 2002 2001 ========================================================================== ========== ========== ========== Net income $ 1,527 $ 989 $ 1,154 Other comprehensive income(loss) items: Foreign currency translation adjustments (a) 38 5 (12) Derivative mark-to-market adjustments (b) 2 (6) (20) Minimum pension liability adjustments (c) 13 (5) (6) Unrealized gains on securities (d) 24 65 2 ---------- ---------- ---------- Other comprehensive income(loss), net of tax 77 59 (36) ---------- ---------- ---------- Comprehensive income $ 1,604 $ 1,048 $ 1,118 ========================================================================== ========== ========== ==========
(a) Net of tax of $15 million, $0 million and $0 million in 2003, 2002 and 2001, respectively. (b) Net of tax of $1 million, $(5) million and $(11) million in 2003, 2002 and 2001, respectively. (c) Net of tax of $7 million, $(3) million and $(3) million in 2003, 2002 and 2001, respectively. (d) Net of tax of $13 million, $35 million and $0 million in 2003, 2002 and 2001, respectively. The accompanying notes are an integral part of these financial statements. 36
CONSOLIDATED STATEMENTS OF CASH FLOWS Occidental Petroleum Corporation In millions and Subsidiaries For the years ended December 31, 2003 2002 2001 ================================================================================ ========== ========== ========== CASH FLOW FROM OPERATING ACTIVITIES Income from continuing operations $ 1,595 $ 1,163 $ 1,179 Adjustments to reconcile income to net cash provided by operating activities: Depreciation, depletion and amortization of assets 1,177 1,012 965 Amortization of debt discount and deferred financing costs 6 7 5 Deferred income tax provision(benefit) 61 (141) (183) Other noncash charges to income 313 62 106 Gains on disposition of assets, net (32) (10) (10) Loss from equity investments 9 261 504 Dry hole and impairment expense 80 96 99 Changes in operating assets and liabilities: (Increase) decrease in accounts and notes receivable (225) (342) 1,085 (Increase) decrease in inventories (3) (73) 37 (Increase) decrease in prepaid expenses and other assets (49) (39) 72 Increase (decrease) in accounts payable and accrued liabilities 84 172 (1,150) Increase in current domestic and foreign income taxes 231 115 4 Other operating, net (173) (174) (152) ---------- ---------- ---------- Operating cash flow from continuing operations 3,074 2,109 2,561 Operating cash flow from discontinued operations -- (9) 5 ---------- ---------- ---------- NET CASH PROVIDED BY OPERATING ACTIVITIES 3,074 2,100 2,566 ---------- ---------- ---------- CASH FLOW FROM INVESTING ACTIVITIES Capital expenditures (1,601) (1,236) (1,308) Sale of businesses and disposal of property, plant and equipment, net 70 41 852 Purchase of businesses, net (351) (492) (46) Equity investments and other, net (139) (5) (141) ---------- ---------- ---------- Investing cash flow from continuing operations (2,021) (1,692) (643) Investing cash flow from discontinued operations -- (4) (8) ---------- ---------- ---------- NET CASH USED BY INVESTING ACTIVITIES (2,021) (1,696) (651) ---------- ---------- ---------- CASH FLOW FROM FINANCING ACTIVITIES Proceeds from long-term debt 297 248 861 Payments of long-term debt, non-recourse debt and capital lease liabilities (631) (199) (2,258) Proceeds from issuance of common stock 10 22 18 Repurchase of trust preferred securities (2) (9) (11) Purchases for natural gas delivery commitment -- (95) (121) Buyout of natural gas commitment, net -- (179) -- Payments of notes payable, net -- -- (2) Proceeds from subsidiary preferred stock issuance -- 72 -- Cash dividends paid (392) (375) (372) Stock options exercised 200 60 72 Other financing, net 2 (1) (1) ---------- ---------- ---------- Financing cash flow from continuing operations (516) (456) (1,814) Financing cash flow from discontinued operations -- -- -- ---------- ---------- ---------- NET CASH USED BY FINANCING ACTIVITIES (516) (456) (1,814) ---------- ---------- ---------- INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 537 (52) 101 CASH AND CASH EQUIVALENTS--BEGINNING OF YEAR 146 198 97 ---------- ---------- ---------- CASH AND CASH EQUIVALENTS--END OF YEAR $ 683 $ 146 $ 198 ================================================================================ ========== ========== ==========
The accompanying notes are an integral part of these financial statements. 37 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Occidental Petroleum Corporation and Subsidiaries NOTE 1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES -------------------------------------------------------------------------------- PRINCIPLES OF CONSOLIDATION The consolidated financial statements include the accounts of Occidental Petroleum Corporation, entities where it owns a majority voting interest, variable-interest entities (VIE) where it is the primary beneficiary and its undivided interests in oil and gas exploration and production ventures. In these Notes, the term "Occidental" or "the company" refers to Occidental Petroleum Corporation and/or one or more entities where it owns a majority voting interest. The company's proportionate share of oil and gas exploration and production ventures, where it has a direct working interest, is accounted for by reporting its proportionate share of assets, liabilities, revenues and costs within the relevant lines on the balance sheets, income statements and cash flow statements. In addition, certain financial statements, notes and supplementary data for prior years have been changed to conform to the 2003 presentation. INVESTMENTS IN UNCONSOLIDATED ENTITIES Investments in unconsolidated entities include both equity method investments and available-for-sale investments. Amounts representing Occidental's percentage interest in the underlying net assets of affiliates (excluding undivided interests in oil and gas exploration and production ventures) in which it does not have a majority voting interest but as to which it exercises significant influence, are accounted for under the equity method. The company reviews equity method investments for impairment whenever events or changes in circumstances indicate that an other-than-temporary decline in value has occurred. The amount of impairment, if any, is based on quoted market prices, where available, or other valuation techniques, including discounted cash flows. Investments in which Occidental does not exercise significant influence are accounted for as available-for-sale investments in accordance with Statements of Financial Accounting Standards (SFAS) No. 115, "Accounting for Certain Investments in Debt and Equity Securities." Under SFAS No. 115, available-for-sale investments are carried at fair value, based on quoted market prices, with unrealized gains and losses reported in Other Comprehensive Income (OCI), net of taxes, until such investment is sold or collected. In disposal, the accumulated unrealized gain or loss included in OCI is transferred to income. REVENUE RECOGNITION For oil and gas, title passes to the customer when product is shipped. Revenue is recognized when title has passed to the customer. Prices are either fixed or based on a market index. For marketing and trading activities, revenue is recognized on settled transactions upon completion of contract terms, and for physical deliveries, upon title transfer. For unsettled transactions, contracts that meet specified accounting criteria are marked to market (see "Accounting Changes" in Note 4). Revenue from chemical product sales is recognized when the product is shipped and title has passed to the customer. Prices are fixed at the time of shipment. Customer incentive programs provide for payments or credits to be made to customers based on the volume of product purchased over a defined period. Total customer incentive payments over a given period are estimated and recorded as a reduction to revenue ratably over the contract period. Such estimates are evaluated and revised as warranted. NATURE OF OPERATIONS Occidental is a multinational organization whose principal business segments are oil and gas and chemical. The oil and gas segment explores for, develops, produces and markets crude oil and natural gas. The chemical segment manufactures and markets basic chemicals, vinyls and performance chemicals. RISKS AND UNCERTAINTIES The process of preparing consolidated financial statements in conformity with generally accepted accounting principles requires the use of estimates and assumptions regarding certain types of assets, liabilities, revenues and expenses. Such estimates primarily relate to unsettled transactions and events as of the date of the consolidated financial statements. Accordingly, upon settlement, actual results may differ from estimated amounts, generally not by material amounts. Management believes that these estimates and assumptions provide a reasonable basis for the fair presentation of Occidental's financial position and results of operations. 38 Included in the accompanying consolidated balance sheet are deferred tax assets of $839 million as of December 31, 2003, the noncurrent portion of which is netted against deferred income tax liabilities. Realization of these assets is dependent upon Occidental generating sufficient future taxable income. Occidental expects to realize the recorded deferred tax assets through future operating income and reversal of taxable temporary differences. The accompanying consolidated balance sheet includes assets of approximately $3.3 billion as of December 31, 2003, relating to Occidental's operations in countries outside North America. Some of these countries may be considered politically and economically unstable. These assets and the related operations are subject to the risk of actions by governmental authorities and insurgent groups. Occidental attempts to conduct its financial affairs so as to mitigate its exposure against such risks and would expect to receive compensation in the event of nationalization. Since Occidental's major products are commodities, significant changes in the prices of oil and gas and chemical products may have a significant impact on Occidental's results of operations for any particular year. Also, see "Property, Plant and Equipment" below. FOREIGN CURRENCY TRANSACTIONS The functional currency applicable to all of Occidental's foreign oil and gas operations is the U.S. dollar since cash flows are denominated principally in U.S. dollars. Occidental's chemical operations in Brazil use the Real as the functional currency. The effect of exchange-rate changes on transactions denominated in nonfunctional currencies generated a gain(loss) of $0 in 2003, $(26) million in 2002 and $1 million in 2001. The 2002 amount related to the writedown and sale of Occidental's calendering operations in Rio de Janeiro, Brazil. CASH AND CASH EQUIVALENTS Cash equivalents are short-term, highly liquid investments that are readily convertible to cash. Cash equivalents totaled approximately $661 million and $116 million at December 31, 2003 and 2002, respectively. TRADE RECEIVABLES Occidental has an agreement in place to sell, under a revolving sale program, an undivided interest in a designated pool of non-interest bearing trade receivables. This program is used by Occidental as a low-cost source of working capital funding. The balance of receivables sold at December 31, 2003 and 2002 was $360 million. This amount is not included in the debt and related trade receivables accounts, respectively, on Occidental's consolidated balance sheets. Receivables must meet certain criteria to qualify for the program. Under this program, Occidental serves as the collection agent with respect to the receivables sold. An interest in new receivables is sold as collections are made from customers. Fees and expenses under this program are included in selling, general and administrative and other operating expenses. During the years ended December 31, 2003, 2002 and 2001, the cost of this program amounted to approximately 1.5 percent, 2.1 percent and 4.5 percent, respectively, of the weighted average amount of the receivables sold in each year. The fair value of any retained interests in the receivables sold is not material. The buyers of the receivables are protected against significant risk of loss on their purchase of receivables. Occidental provides for allowances for any doubtful receivables based on its periodic evaluation of such receivables. The provisions for such receivables were not material in the years ended December 31, 2003, 2002 and 2001. The program can terminate upon the occurrence of certain events, which generally are under Occidental's control or relate to bankruptcy. In such an event, alternative funding would have to be arranged, which could result in an increase in debt recorded on the consolidated balance sheet, with a corresponding increase in the accounts receivable balance. The consolidated income statement effect of such an event would not be significant. INVENTORIES For the oil and gas segment, materials and supplies are valued at the lower of average cost or market. Inventories are reviewed periodically (at least annually) for obsolescence. Oil and natural gas liquids (NGLs) inventories, which typically represent the last few days of production at the end of each period, and natural gas trading inventory are valued at the lower of cost or market. Natural gas trading inventory was valued at market prior to January 1, 2003 (see "Accounting Changes" in Note 4). For the chemical segment, in countries where allowable, Occidental generally values its inventories using the last-in, first-out (LIFO) method as it better matches current costs and current revenue. Accordingly, Occidental accounts for most of its domestic inventories in its chemical business, other than materials and supplies, on the LIFO method. For other countries, Occidental uses the first-in, first-out (FIFO) method (if the costs of goods are specifically identifiable) or the average-cost method (if the costs of goods are not specifically identifiable). Materials and supplies are accounted for using a weighted average cost method. 39 PROPERTY, PLANT AND EQUIPMENT OIL AND GAS Property additions and major renewals and improvements are capitalized at cost. Interest costs incurred in connection with major capital expenditures are capitalized and amortized over the lives of the related assets (see Note 16). Occidental uses the successful efforts method to account for its oil and gas properties. Under this method, costs of acquiring properties, costs of drilling successful exploration wells and development costs are capitalized. Annual lease rentals, exploration costs, geological, geophysical and seismic costs and exploratory dry-hole costs are expensed as incurred. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and NGLs that geological and engineering data demonstrate with reasonable certainty can be recovered in future years from known reservoirs under existing economic and operating conditions considering future production and development costs. Depreciation and depletion of oil and gas producing properties is determined by the unit-of-production method. The carrying value of Occidental's property, plant and equipment (PP&E) is based on the cost incurred to acquire the PP&E, net of accumulated depreciation and net of any impairment charges. Occidental is required to perform impairment tests on its assets whenever events or changes in circumstances lead to a reduction in the estimated useful lives or estimated future cash flows that would indicate that the carrying amount may not be recoverable, or when management's plans change with respect to those assets. Under the provisions of SFAS No. 144, Occidental must compare the undiscounted future cash flows of an asset to its carrying value. A portion of the carrying value of Occidental's oil and gas properties are attributable to unproved properties. At December 31, 2003, the costs attributable to unproved properties were approximately $900 million. These costs are not currently being depreciated or depleted. As exploration and development work progresses and the reserves on these properties are proven, capitalized costs attributable to the properties will be subject to depreciation and depletion. If the exploration and development work were to be unsuccessful, the capitalized costs of the properties related to this unsuccessful work would be expensed in the year in which the determination was made. The timing of any writedowns of these unproven properties, if warranted, depends upon the nature, timing and extent of future exploration and development activities and their results. Occidental believes its exploration and development efforts will allow it to realize the unproved property balance. CHEMICAL Occidental's chemical plants are depreciated using either the unit-of-production or straight-line method based upon the estimated useful life of the facilities. The estimated useful lives of Occidental's chemical assets, which range from 3 years to 50 years, are used to compute depreciation expense and are also used for impairment tests. The estimated useful lives used for the chemical facilities are based on the assumption that Occidental will provide an appropriate level of annual expenditures to maintain the facilities in good operating condition. Without these continued expenditures, the useful lives of these plants could significantly decrease. Other factors which could change the estimated useful lives of Occidental's chemical plants include higher or lower product prices, which are particularly affected by both domestic and foreign competition, feedstock costs, energy prices, environmental regulations, competition and technological changes. Occidental is required to perform impairment tests on its chemical assets whenever events or changes in circumstances lead to a reduction in the estimated useful lives or estimated future cash flows that would indicate that the carrying amount may not be recoverable, or when management's plans change with respect to those assets. Under the provisions of SFAS No. 144, Occidental must compare the undiscounted future cash flows of an asset to its carrying value. The key factors which could significantly affect future cash flows are future product prices, which are particularly affected by both domestic and foreign competition, feedstock costs, energy costs, significantly increased regulation and remaining estimated useful life. Due to a temporary decrease in demand for some of its products, Occidental temporarily idled an ethylene dichloride (EDC) plant in June 2001, a chlor-alkali plant in December 2001 and a portion of a chlor-alkali plant in June 2003. These facilities will remain idle until market conditions improve. Management expects that these plants will become operational in the future. The net book value of these plants was $156 million at December 31, 2003. Based on year-end value, the chlor-alkali plant that closed in December 2001 has a 24-percent minority interest of $28 million. These facilities are periodically tested for impairment and, based on the results, no impairment is deemed necessary at this time. Occidental continues to depreciate these facilities based on their remaining estimated useful lives. ACCRUED LIABILITIES--CURRENT Accrued liabilities include accrued payroll, commissions and related expenses of $200 million and $159 million at December 31, 2003 and 2002, respectively. 40 ENVIRONMENTAL LIABILITIES AND EXPENDITURES Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Reserves for estimated costs that relate to existing conditions caused by past operations and that do not contribute to current or future revenue generation are recorded when environmental remedial efforts are probable and the costs can be reasonably estimated. In determining the reserves and the reasonably possible range of loss, Occidental refers to currently available information, including relevant past experience, available technology, regulations in effect, the timing of remediation and cost-sharing arrangements. The environmental reserves are based on management's estimate of the most likely cost to be incurred and are reviewed periodically and adjusted as additional or new information becomes available. For the years ended December 31, 2003 and 2002, Occidental has not accrued any reimbursements or indemnification recoveries for environmental remediation matters as assets. Recoveries and reimbursements are recorded in income when receipt is probable. Environmental reserves are recorded on a discounted basis only when a reserve is initially established and the aggregate amount of the estimated costs for a specific site and the timing of cash payments are reliably determinable. The reserve methodology for a specific site is not modified once it has been established. Many factors could result in changes to Occidental's environmental reserves and reasonably possible range of loss. The most significant are: >> The original cost estimate may have been inaccurate. >> Modified remedial measures might be necessary to achieve the required remediation results. Occidental generally assumes that the remedial objective can be achieved using the most cost-effective technology reasonably expected to achieve that objective. Such technologies may include air sparging or phyto-remediation of shallow groundwater, or limited surface soil removal or in-situ treatment producing acceptable risk assessment results. Should such remedies fail to achieve remedial objectives, more intensive or costly measures may be required. >> The remedial measure might take more or less time than originally anticipated to achieve the required contaminant reduction. Site-specific time estimates can be affected by factors such as groundwater capture rates, anomalies in subsurface geology, interactions between or among water-bearing zones and non-water-bearing zones, or the ability to identify and control contaminant sources. >> The regulatory agency might ultimately reject or modify Occidental's proposed remedial plan and insist upon a different course of action. Additionally, other events might occur that could affect Occidental's future remediation costs, such as: >> The discovery of more extensive contamination than had been originally anticipated. For some sites with impacted groundwater, accurate definition of contaminant plumes requires years of monitoring data and computer modeling. Migration of contaminants may follow unexpected pathways along geologic anomalies that could initially go undetected. Additionally, the size of the area requiring remediation may change based upon risk assessment results following site characterization or interim remedial measures. >> Improved remediation technology might decrease the cost of remediation. In particular, for groundwater remediation sites with projected long-term operation and maintenance, the development of more effective treatment technology, or acceptance of alternative and more cost-effective treatment methodologies such as bio-remediation, could significantly affect remediation costs. >> Laws and regulations might change to impose more or less stringent remediation requirements. At sites involving multiple parties, Occidental provides environmental reserves based upon its expected share of liability. When other parties are jointly liable, the financial viability of the parties, the degree of their commitment to participate and the consequences to Occidental of their failure to participate are evaluated when estimating Occidental's ultimate share of liability. Based on these factors, Occidental believes that it will not be required to assume a share of liability of other potentially responsible parties, with whom it is alleged to be jointly liable, in an amount that would have a material effect on Occidental's consolidated financial position, liquidity or results of operations. Most cost sharing arrangements with other parties fall into one of the following three categories: Category 1: Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) or state-equivalent sites wherein Occidental and other alleged potentially responsible parties share the cost of remediation in accordance with negotiated or prescribed allocations; Category 2: Oil and gas joint ventures wherein each joint venture partner pays its proportionate share of remedial cost; and Category 3: Contractual arrangements typically relating to purchases and sales of property wherein the parties to the transaction agree to methods of allocating the costs of environmental remediation. In all three of these categories, Occidental records as a reserve its expected net cost of remedial activities, as adjusted by recognition for any non-performing parties. 41 In addition to the costs of investigating and implementing remedial measures, which often take in excess of ten years at CERCLA sites, Occidental's reserves include management's estimates of the cost of operation and maintenance of remedial systems. To the extent that the remedial systems are modified over time in response to significant changes in site-specific data, laws, regulations, technologies or engineering estimates, Occidental reviews and changes the reserves accordingly on a site-specific basis. ASSET RETIREMENT OBLIGATIONS Occidental adopted SFAS No. 143, "Accounting for Asset Retirement Obligations", on January 1, 2003 (see "Accounting Changes" in Note 4). The following table summarizes the activity of the asset retirement obligations:
For the year ended December 31, (in millions) 2003 ================================================================================ ========== Beginning balance $ -- Cumulative effect of change in accounting principles 151 Liabilities incurred 6 Liabilities settled (7) Accretion expense 11 Acquisitions and other 1 Revisions to estimated cash flows 5 ---------- ENDING BALANCE $ 167 ================================================================================ ==========
Before 2003, the estimated future abandonment costs of offshore oil and gas properties and removal costs for platforms, net of salvage value, were accrued over their operating lives. Such costs were calculated at unit-of-production rates based upon estimated proved recoverable reserves and were taken into account in determining depreciation, depletion and amortization. Occidental assumed that the salvage value of the oil and gas property would equal the dismantlement, restoration and reclamation costs for onshore production, so no accrual was deemed necessary. For the chemical segment, appropriate reserves were provided when a decision was made to dispose of a property, since Occidental makes capital renewal expenditures on a continual basis while an asset is in operation. DERIVATIVE INSTRUMENTS On January 1, 2001, Occidental adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended. This statement required an entity to recognize derivatives on the balance sheet and measure those instruments at fair value. Adoption of this new accounting standard resulted in cumulative after-tax reductions in net income of approximately $24 million and OCI of approximately $27 million in the first quarter of 2001. The adoption also increased total assets by $588 million and total liabilities by $639 million as of January 1, 2001. Occidental applies either fair value or cash flow hedge accounting when transactions meet specified criteria to obtain hedge accounting treatment. If the derivative does not qualify as a hedge or is not designated as a hedge, the gain or loss is immediately recognized in earnings. If the derivative qualifies for hedge accounting, the gain or loss on the derivative is either recognized in income with an offsetting adjustment to the basis of the item being hedged for fair value hedges, or deferred in OCI to the extent the hedge is effective for cash flow hedges. A hedge is regarded as highly effective and qualifies for hedge accounting if, at inception and throughout its life, it is expected that changes in the fair value or cash flows of the hedged item are almost fully offset by the changes in the fair value of changes in cash flows of the hedging instrument and actual effectiveness is within a range of 80 percent to 125 percent. In the case of hedging a forecasted transaction, the transaction must be highly probable and must present an exposure to variations in cash flows that could ultimately affect reported net profit or loss. Occidental discontinues hedge accounting when it is determined that a derivative has ceased to be highly effective as a hedge; when the derivative expires, or is sold, terminated, or exercised; when the hedged item matures or is sold or repaid; or when a forecasted transaction is no longer deemed highly probable. Derivative assets are classified in receivables from joint ventures, partnerships and other, and long-term receivables; derivative liabilities are reported in accrued liabilities and deferred credits and other liabilities - other. FINANCIAL INSTRUMENTS FAIR VALUE Occidental values financial instruments as required by SFAS No. 107, "Disclosures about Fair Value of Financial Instruments." The carrying amounts of cash and cash equivalents approximate fair value because of the short maturity of those instruments. The carrying value of other on-balance-sheet financial instruments, other than debt, approximates fair value, and the cost, if any, to terminate off-balance-sheet financial instruments is not significant. 42 STOCK INCENTIVE PLANS Occidental has stock incentive plans (Plans) that are more fully described in Note 12. Occidental accounts for those Plans under APB No. 25, "Accounting for Stock Issued to Employees", and related interpretations. Occidental's policy is to recognize compensation expense for the Plans over the vesting period of the award. Had compensation expense for those Plans been determined in accordance with SFAS No. 123, "Accounting for Stock Based Compensation", Occidental's pro-forma net income and earnings per share would have been as follows:
Year ended December 31, (in millions) 2003 2002 2001 ========================================================================================= ========== ========== ========== Net income, as reported $ 1,527 $ 989 $ 1,154 Add: Stock-based employee compensation expense included in reported net income determined under APB No. 25, net of related tax effects 38 18 16 Deduct: Total stock-based employee compensation expense determined under the SFAS No. 123 fair-value-based method for all awards, net of related tax effects (56) (37) (33) ---------- ---------- ---------- Pro-forma net income $ 1,509 $ 970 $ 1,137 ========================================================================================= ========== ========== ========== Earnings Per Share: Basic - as reported $ 3.98 $ 2.63 $ 3.10 Basic - pro forma $ 3.93 $ 2.58 $ 3.06 Diluted Earnings per Share Diluted - as reported $ 3.93 $ 2.61 $ 3.09 Diluted - pro forma $ 3.88 $ 2.55 $ 3.04 ----------------------------------------------------------------------------------------- ---------- ---------- ----------
The fair value of each option grant, for pro-forma calculation purposes, is estimated using the Black-Scholes option-pricing model. The weighted average grant-date fair value of options granted was $3.20, $5.36 and $5.90 in 2003, 2002 and 2001, respectively. The fair value of each option grant is estimated with the following weighted average assumptions:
Year ended December 31, 2003 2002 2001 ================================================================================ ========== ========== ========== Assumptions used: Risk-free interest rate 1.63% 3.89% 4.84% Dividend yield 3.37% 3.93% 3.74% Volatility factor 21% 32% 29% Expected life (years) 2.4 3.5 5.0 -------------------------------------------------------------------------------- ---------- ---------- ----------
These grants have limitations on transferability. In the case of executive management, such options may not be exercised for approximately two months of each calendar quarter. The use of short-term volatility measures as a proxy for long-term volatility provides significant uncertainty as to the fair value of the options. These factors could result in the market value of the options being less than the Black-Scholes values. SUPPLEMENTAL CASH FLOW INFORMATION Cash payments, net of refunds, during the years 2003, 2002 and 2001 included federal, foreign and state income taxes of approximately $538 million, $111 million and $408 million, respectively. Interest paid (net of interest capitalized) totaled approximately $310 million, $250 million and $389 million for the years 2003, 2002 and 2001, respectively. (See Note 3 for detail of noncash investing and financing activities regarding certain acquisitions.) NOTE 2 DERIVATIVE ACTIVITIES INCLUDING FAIR VALUE OF FINANCIAL INSTRUMENTS -------------------------------------------------------------------------------- Occidental's market risk exposures relate primarily to commodity prices and, to a lesser extent, interest rates and foreign currency exchange rates. Occidental periodically enters into derivative instrument transactions to reduce these price and rate fluctuations. A derivative is a financial instrument that derives its value from another instrument or variable. In general, the fair value recorded for derivative instruments is based on quoted market prices, dealer quotes and the Black-Scholes or similar valuation models. 43 COMMODITY PRICE RISK GENERAL Occidental's results are sensitive to fluctuations in crude oil and natural gas prices. MARKETING AND TRADING OPERATIONS Occidental periodically uses different types of derivative instruments to achieve the best prices for oil and gas. Derivatives are also used by Occidental to reduce its exposure to price volatility and mitigate fluctuations in commodity-related cash flows. Occidental enters into low-risk marketing and trading activities through its separate marketing organization, which operates under established policy controls and procedures. With respect to derivatives used in its oil and gas marketing operations, Occidental utilizes a combination of futures, forwards, options and swaps to offset various physical transactions. Overall, Occidental has a low level of involvement in the hedging of long-term oil and gas prices and its use of derivatives in hedging activity remains at a correspondingly low level. In September 2002, Occidental unwound its natural gas delivery commitment and corresponding natural gas price swap, which were entered into in November 1998. Occidental recognized a pre-tax loss of $3 million related to these transactions. COMMODITY HEDGES On a limited basis, Occidental uses cash-flow hedges for the sale of crude oil and natural gas production. Occidental's commodity cash-flow-hedging instruments were used in 2002 for the sale of production and were highly effective. At December 31, 2002, all of these cash-flow hedges had been settled. No fair value hedges were used for oil and gas production during 2003 or 2002 and no cash flow hedges were used for the sale of production in 2003. INTEREST RATE RISK GENERAL Occidental is exposed to risk resulting from changes in interest rates and it enters into various derivative financial instruments to manage interest-rate exposure. Interest-rate swaps, forward locks and futures contracts are entered into periodically as part of Occidental's overall strategy. HEDGING ACTIVITIES Occidental has entered into several interest-rate swaps that qualified for fair-value hedge accounting. These derivatives effectively convert approximately $1.8 billion of fixed-rate debt to variable-rate debt with maturities ranging from 2005 to 2009. Occidental was a party to a series of forward interest-rate locks, which qualified as cash-flow hedges. The hedges were related to the construction of a cogeneration plant leased by Occidental that was completed in December 2002. The remaining loss on the hedges through December 2003 was approximately $21 million after-tax, which is recorded in accumulated OCI and is being recognized in earnings over the lease term of 26 years on a straight-line basis. Certain of Occidental's equity investees have entered into additional derivative instruments that qualify as cash-flow hedges. Occidental reflects its proportionate share of these cash-flow hedges in OCI. CREDIT RISK Occidental's energy contracts are spread among numerous counterparties. Creditworthiness is reviewed before doing business with a new counterparty and on an ongoing basis. Occidental monitors aggregated counterparty exposure relative to credit limits, and manages credit-enhancement issues. Credit exposure for each customer is monitored for outstanding balances, current month activity, and forward mark-to-market exposure. FOREIGN CURRENCY RISK Several of Occidental's foreign operations are located in countries whose currencies generally depreciate against the U.S. dollar. Typically, effective currency forward markets do not exist for these countries. Therefore, Occidental attempts to manage its exposure primarily by balancing monetary assets and liabilities and maintaining cash positions only at levels necessary for operating purposes. Generally, international crude oil sales are denominated in U.S. dollars. Additionally, all of Occidental's oil and gas foreign entities have the U.S. dollar as the functional currency. However, in one foreign chemical subsidiary where the local currency is the functional currency, Occidental has exposure on U.S. dollar-denominated debt that is not material. At December 31, 2003 and 2002, Occidental had not entered into any foreign currency derivative instruments. The effect of exchange-rate transactions in foreign currencies is included in periodic income. 44 DERIVATIVE AND FAIR VALUE DISCLOSURES The following table shows derivative financial instruments included in the consolidated balance sheets:
Balance at December 31, (in millions) 2003 2002 ================================================================================ ========== ========== Derivative financial instrument assets (a) Current $ 138 $ 164 Non-current 118 157 ---------- ---------- $ 256 $ 321 ========== ========== Derivative financial instrument liabilities (a) Current $ 85 $ 115 Non-current 23 23 ---------- ---------- $ 108 $ 138 ================================================================================ ========== ==========
(a) Amounts include energy-trading contracts As a result of fair-value hedges, the amount of interest expense recorded in the income statement was lower by approximately $58 million and $45 million for the years ended December 31, 2003 and 2002, respectively. The following table summarizes after-tax derivative activity recorded in OCI:
Balance at December 31, (in millions) 2003 2002 ================================================================================ ========== ========== Beginning Balance $ (26) $ (20) Losses from changes in current cash flow hedges (17) (14) Amount reclassified to income 19 8 ---------- ---------- Ending Balance $ (24) $ (26) ================================================================================ ========== ==========
During the next twelve months, Occidental expects that approximately $3 million of net derivative after-tax losses included in OCI, based on their valuation at December 31, 2003, will be reclassified into earnings when the hedged transactions close. Hedge ineffectiveness did not have a significant impact on earnings for the years ended December 31, 2003 and 2002. NOTE 3 BUSINESS COMBINATIONS AND ASSET ACQUISITIONS AND DISPOSITIONS -------------------------------------------------------------------------------- 2003 In 2003, Occidental made several oil and gas acquisitions in the Permian Basin for approximately $317 million in cash and sold approximately $34 million of these assets shortly thereafter. No gain or loss was recorded on these sales. 2002 In 2002, Occidental purchased a 24.5-percent interest in the Dolphin Project for $310 million. This investment includes a 24.5-percent interest in Dolphin Energy Limited (Dolphin Energy), the operator of the Dolphin Project. The Dolphin Project consists of two parts: (1) a development and production sharing agreement with Qatar to develop and produce natural gas and condensate in Qatar's North Field for 25 years, with a provision to request a 5-year extension, which will be proportionately consolidated by Occidental; and (2) the rights for Dolphin Energy to build, own and operate a 260-mile-long, 48-inch export pipeline to transport 2 billion cubic feet per day of dry natural gas from Qatar to markets in the United Arab Emirates (UAE) for the life of the Dolphin Project and longer, which will be accounted for as an equity investment. The pipeline will have capacity to transport up to 3.2 billion cubic feet per day, which will allow for additional business opportunities. Approximately $250 million of the purchase price was allocated to the equity investment, while the remaining amount was recorded in PP&E. Several important milestones have been reached since Occidental joined the Dolphin Project. In 2002, two development wells were tested, providing sufficient information to complete the field development plan. In October 2003, Dolphin Energy signed two 25-year contracts to supply approximately one BCF of natural gas per day to two entities in the UAE. In December 2003, the Government of Qatar approved the final field development plan for the Dolphin Project. Based on the foregoing developments, Occidental recorded 107 million barrels of oil equivalent (BOE) (unaudited) of proved undeveloped oil and gas reserves in 2003. As the project has not begun operation, no revenue or production costs were recorded in 2003. 45 Most recently, in January 2004, Dolphin Energy awarded engineering, procurement and construction contracts for the gas processing and compression plant at Ras Laffan in Qatar as well as for two offshore gas production platforms. The projected start-up date for production is in 2006. In August 2002, Occidental and Lyondell Chemical Company completed an agreement for Occidental to sell its 29.5-percent share of Equistar to Lyondell and to purchase a 21-percent equity interest in Lyondell. Occidental entered into these transactions to diversify its petrochemicals interests. These transactions reduced Occidental's direct exposure to petrochemicals volatility, yet will allow it to preserve, through its Lyondell investment, an economic upside of a recovery in the petrochemicals industry. In connection with these transactions, Occidental wrote down its investment in the Equistar partnership to fair value by recording a $412 million pre-tax charge as of December 2001. After the write-down, the net book value of Occidental's investment in Equistar at December 31, 2001, after considering tax effects, approximated the fair value of the Lyondell shares Occidental expected to receive, less transaction costs. Occidental recorded an after-tax gain of $164 million in the third quarter of 2002, as a result of closing these transactions on August 22, 2002. Occidental's initial carrying value of the Lyondell investment was $489 million, which represented the fair value of Lyondell's shares at closing. In 2002, Occidental increased its ownership in Badin Block 1 and 2R by purchasing additional interests in these two blocks from the Government of Pakistan for approximately $72 million. In the fourth quarter of 2002, Occidental sold its chrome business at Castle Hayne, North Carolina for $25 million and its plastic calendering operations in Brazil for a $6 million note receivable. In the third quarter of 2002, Occidental recorded an after-tax impairment charge of $69 million and classified both of these businesses as discontinued operations. The fair value of these businesses was determined by the expected sales proceeds from third party buyers. When these transactions closed, no significant gain or loss was recorded. For the years ended December 31, 2002 and 2001, the discontinued operations had revenues of $91 million and $124 million, respectively, and pre-tax income (loss) of $(98) million and $2 million, respectively. 2001 On August 31, 2001, Occidental sold its interest in a subsidiary that owned a Texas intrastate pipeline system. The entity was sold to Kinder Morgan Energy Partners, L.P. for $360 million. Occidental recorded an after-tax loss of approximately $272 million in connection with this transaction. On July 10, 2001, Occidental completed the sale of its interest in the Tangguh liquefied natural gas (LNG) project in Indonesia to Mitsubishi Corporation of Japan for proceeds of $503 million. Occidental recorded an after-tax gain of approximately $399 million for this transaction. NOTE 4 ACCOUNTING CHANGES -------------------------------------------------------------------------------- SFAS NO. 132 REVISED In December 2003, the Financial Accounting Standards Board (FASB) issued a revision to SFAS No. 132, "Employers Disclosures about Pensions and Other Postretirement Benefits" to improve financial statement disclosures for defined benefit plans. The standard requires that companies provide more details about their plan assets, benefit obligations, cash flows and other relevant information, such as plan assets by category. A description of investment policies and strategies for these asset categories and target allocation percentages or target ranges are also required in financial statements. This statement is effective for financial statements with fiscal years ending after December 15, 2003. Occidental adopted this statement in the fourth quarter of 2003 and provided the required disclosures in Note 13. SFAS NO. 150 In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity." SFAS No. 150 establishes accounting standards for how a company classifies and measures financial instruments that have characteristics of liabilities and equity. Occidental adopted the provisions of this statement on July 1, 2003. As a result of the adoption, Occidental's mandatorily redeemable trust preferred securities are now classified as a liability and the payments to the holders of the securities, which were previously recorded as minority interest on the statement of operations, are recorded as interest expense. On January 20, 2004, all of the trust preferred securities were redeemed. SFAS NO. 149 In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities." SFAS No. 149 amends and clarifies financial accounting and reporting for derivative instruments. This statement is effective for contracts entered into or modified after June 30, 2003. Occidental adopted this statement in the third quarter of 2003 and it did not have a material effect on its financial statements. 46 FIN 46 AND FIN 46-R (REVISED) In January 2003, the FASB issued FASB Interpretation No. (FIN) 46, "Consolidation of Variable Interest Entities." FIN 46 requires a company to consolidate a VIE if it is designated as the primary beneficiary of that entity even if the company does not have a majority of voting interests. A VIE is generally defined as an entity whose equity is unable to finance its activities or whose owners lack the risks and rewards of ownership. The statement also imposes disclosure requirements for all the VIEs of a company, even if the company is not the primary beneficiary. The provisions of this statement apply at inception for any entity created after January 31, 2003. Occidental adopted the provisions of this Interpretation for its existing entities on April 1, 2003, which resulted in the consolidation of its OxyMar investment. As a result of the OxyMar consolidation, assets increased by $166 million and liabilities increased by $178 million. There was no material effect on net income as a result of the consolidation. In September 2003, Marubeni indicated it would exercise its option to put its interest in OxyMar to Occidental by paying approximately $25 million to Occidental. In connection with the transfer, which is expected to be complete in April 2004, Occidental will assume Marubeni's guarantee of OxyMar's debt. As all the OxyMar debt is already consolidated in Occidental's financial statements with the adoption of FIN 46, the exercise of the put will not have a material effect on Occidental's financial position or results of operations. See Note 14 for more information on VIEs where Occidental is not the primary beneficiary. In December 2003, the FASB revised FIN 46 to exempt certain entities from its requirements and to clarify certain issues arising during the initial implementation of FIN 46. Occidental will adopt the revised interpretation in the first quarter of 2004 and it is not expected to have a material impact on the financial statements when adopted. FIN 45 In January 2003, the FASB issued FIN 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others." FIN 45 requires a company to recognize a liability for the obligations it has undertaken in issuing a guarantee. This liability would be recorded at the inception of a guarantee and would be measured at fair value. FIN 45 also requires certain disclosures related to guarantees, which are included in Note 9. Occidental adopted the measurement provisions of this statement in the first quarter of 2003 and it did not have an effect on the financial statements when adopted. EITF ISSUE NO. 02-3 In the third quarter of 2002, Occidental adopted certain provisions of Emerging Issues Task Force (EITF) Issue No. 02-3, "Issues involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities." These provisions prescribed significant changes in how revenue from energy trading is recorded. Historically, Occidental had two major types of oil and gas revenues: (1) revenues from its equity production; and (2) revenues from the sale of oil and gas produced by other companies, but purchased and resold by Occidental, referred to as revenue from trading activities. Both types of sales involve physical deliveries and had been historically recorded on a gross basis in accordance with generally accepted accounting principles. With the adoption of EITF Issue No. 02-3, Occidental now reflects the revenue from trading activities on a net basis. There were no changes in gross margins, net income, cash flow or earnings per share for any period as a result of adopting this requirement. However, net sales and cost of sales were reduced by equal and offsetting amounts to reflect the adoption of this requirement. For the years ended December 31, 2002 and 2001, net sales and cost of sales were reduced from amounts previously reported by approximately $2.2 billion (representing amounts for the first two quarters of 2002) and $5.8 billion, respectively, to conform to the current presentation. Since 1999, Occidental has accounted for certain energy-trading contracts in accordance with EITF Issue No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities." EITF Issue No. 98-10 required that all energy-trading contracts must be marked to fair value with gains and losses included in earnings, whether the contracts were derivatives or not. In October 2002, the EITF rescinded EITF Issue No. 98-10 thus precluding mark-to-market accounting for all energy-trading contracts that are not derivatives and fair value accounting for inventories purchased from third parties. Also, the rescission requires derivative gains and losses to be presented net on the income statement, whether or not they are physically settled, if the derivative instruments are held for trading purposes. Occidental adopted this accounting change in the first quarter of 2003 and recorded a cumulative effect of a change in accounting principles charge of approximately $18 million, after tax. SFAS NO. 146 In July 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities." SFAS No. 146 requires that a liability be recognized for exit and disposal costs only when the liability has been incurred and when it can be measured at fair value. The statement is effective for exit and disposal activities that are initiated after December 31, 2002. Occidental adopted SFAS No. 146 in the first quarter of 2003 and it did not have a material effect on its financial statements. 47 SFAS NO. 145 In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections." In addition to amending or rescinding other existing authoritative pronouncements to make various technical corrections, clarify meanings, or describe their applicability under changed conditions, SFAS No. 145 precludes companies from recording gains and losses from the extinguishment of debt as an extraordinary item. Occidental implemented SFAS No. 145 in the fourth quarter of 2002 and all comparative financial statements have been reclassified to conform to the 2002 presentation. Since Occidental had no 2002 extraordinary items, there was no effect on the 2002 presentation. The effects of the statement on prior years include the reclassification of an extraordinary loss to net income from continuing operations of $8 million ($0.02 per share) in 2001. There was no effect on net income or basic earnings per common share upon adoption. SFAS NO. 143 In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. Under SFAS No. 143, companies are required to recognize the fair value of a liability for an asset retirement obligation in the period in which the liability is incurred if there is a legal obligation to dismantle the asset and reclaim or remediate the property at the end of the useful life. Occidental adopted SFAS No. 143 in the first quarter of 2003. The initial adoption resulted in an after-tax charge of $50 million, which was recorded as a cumulative effect of a change in accounting principles. The adoption increased net property, plant and equipment by $73 million, increased asset retirement obligations by $151 million and decreased deferred tax liabilities by $28 million. The pro-forma asset retirement obligation, if the adoption of this statement had occurred on January 1, 2002, would have been $131 million at January 1, 2002 and $151 million at December 31, 2002. SFAS NO. 142 In June 2001, the FASB issued SFAS No. 142, "Goodwill and Other Intangible Assets." SFAS No. 142 changes the accounting and reporting requirements for acquired goodwill and intangible assets. The provisions of this statement are applied to companies starting with fiscal years beginning after December 15, 2001. At December 31, 2001, the balance sheet included approximately $108 million of goodwill and intangible assets with annual amortization expense of approximately $6 million recorded in each of the years' income statements for the three-year period ended December 31, 2001. As a result, elimination of goodwill amortization would not have had a material impact on net income or earnings per share of any of the years presented and, as a result, the transitional disclosures of adjusted net income excluding goodwill amortization described by SFAS No. 142 have not been presented. Upon implementation of SFAS No. 142 in the first quarter of 2002, three separate specialty chemical businesses were identified as separate reporting units and tested for goodwill impairment. All three of these businesses are components of the chemical segment. The fair value of each of the three reporting units was determined through third party appraisals. The appraisals determined fair value to be the price that the assets could be sold for in a current transaction between willing parties. As a result of the impairment testing, Occidental recorded a cumulative effect of changes in accounting principles after-tax reduction in net income of approximately $95 million due to the impairment of all the goodwill attributed to these reporting units. INTANGIBLE ASSETS The EITF currently is deliberating on EITF No. 03-O, "Whether Mineral Rights Are Tangible or Intangible Assets" and EITF No. 03-S "Application of FASB Statement No. 142, Goodwill and Other Intangible Assets, to Oil and Gas Companies." These proposed statements will determine whether contract-based oil and gas mineral rights are classified as tangible or intangible assets based on the EITF's interpretation of SFAS No. 141 and SFAS No. 142. Historically, Occidental has classified all of its contract-based mineral rights within property, plant and equipment and has generally not identified these amounts separately. If the EITF determines that these mineral rights should be presented as intangible assets, Occidental would have to reclassify its contract-based oil and gas mineral rights acquired after June 30, 2001 to intangible assets and make additional disclosures in accordance with SFAS No. 142. If Occidental adopted this change, approximately $492 million and $226 million of the property, plant and equipment balance would be reclassified to intangible assets at December 31, 2003 and 2002, respectively. These amounts, which are net of accumulated depreciation, depletion and amortization, include approximately $475 million and $210 million of mineral rights related to proved properties at December 31, 2003 and 2002, respectively. Occidental has been amortizing these amounts under the unit-of-production method and would continue to amortize the mineral rights under this method. Based on its understanding of the scope of the EITF deliberations, Occidental believes the adoption of this potential decision would have no material effect on its results of operations. 48 NOTE 5 INVENTORIES -------------------------------------------------------------------------------- Inventories of approximately $171 million and $190 million were valued under the LIFO method at December 31, 2003 and 2002, respectively. Inventories consisted of the following:
Balance at December 31, (in millions) 2003 2002 ================================================================================ ========== ========== Raw materials $ 46 $ 54 Materials and supplies 143 125 Finished goods 342 319 ---------- ---------- 531 498 LIFO reserve (21) (7) ---------- ---------- TOTAL $ 510 $ 491 ================================================================================ ========== ==========
NOTE 6 LONG-TERM DEBT AND TRUST PREFERRED SECURITIES -------------------------------------------------------------------------------- Long-term debt and trust preferred securities consisted of the following:
Balance at December 31, (in millions) 2003 2002 ================================================================================ ========== ========== OCCIDENTAL PETROLEUM CORPORATION 6.75% senior notes due 2012 $ 500 $ 500 7.65% senior notes due 2006 (a) 476 485 6.4% senior notes due 2013, redeemed March 31, 2003 -- 450 7.375% senior notes due 2008 (a) 426 436 8.45% senior notes due 2029 350 350 5.875% senior notes due 2007 (a) 318 323 9.25% senior debentures due 2019, putable August 1, 2004 at par (b) 300 300 4.25% medium-term notes due 2010 300 -- 10.125% senior debentures due 2009 (a) 280 276 7.2% senior debentures due 2028 200 200 4% medium-term notes due 2007 (a) 178 175 6.5% senior notes due 2005 (a) 161 164 8.75% medium-term notes due 2023 100 100 4.101% medium-term notes due 2007 (a) 76 75 Medium-term notes due 2004 through 2008 (8.10% to 8.25% at December 31, 2003) 33 85 11.125% senior notes due 2010 12 12 ---------- ---------- 3,710 3,931 ---------- ---------- SUBSIDIARY DEBT 1.08% to 7.5% unsecured notes due 2006 through 2030 313 280 ---------- ---------- 4,023 4,211 Less: Unamortized discount, net (7) (8) Current maturities (23) (206) ---------- ---------- TOTAL LONG-TERM DEBT 3,993 3,997 TRUST PREFERRED SECURITIES 453 455 ---------- ---------- TOTAL $ 4,446 $ 4,452 ================================================================================ ========== ==========
(a) Amounts include mark-to-market adjustments due to fair-value hedges. (b) Amount is classified as non-current since Occidental does not expect debt holders to put the debt on August 1, 2004. If the debt were put to Occidental, it would refinance this amount on a long-term basis using available lines of long-term bank credit. In January 1999, Occidental issued 21,000,000 shares of 8.16-percent Trust Originated Preferred Securities (trust preferred securities) to the public. Holders of the trust preferred securities are entitled to cumulative cash distributions at an annual rate of 8.16 percent of the liquidation amount of $25 per security. The trust preferred securities must be redeemed by January 20, 2039, but can be redeemed in whole, or in part, beginning January 20, 2004. Starting July 1, 49 2003, upon adoption of SFAS No. 150, the trust preferred securities are classified as a liability, and distributions on the trust preferred securities, which were previously recorded as minority interest on the statement of operations, are recorded as interest expense. On January 20, 2004, Occidental redeemed all of the trust preferred securities for par of $453 million plus accrued interest. At March 31, 2003, Occidental redeemed its 6.4-percent senior notes due 2013 and recorded a pre-tax interest charge of $61 million. At December 31, 2003, Occidental had available lines of committed bank credit of approximately $1.5 billion. Bank fees on these committed lines of credit ranged from 0.100 percent to 0.225 percent. At December 31, 2003, minimum principal payments on long-term debt subsequent to December 31, 2004 aggregated $3,913 million, of which $157 million is due in 2005, $496 million in 2006, $550 million in 2007, $405 million in 2008, $276 million in 2009 and $2,029 million thereafter. These amounts do not include the unamortized discount of $7 million and fair-value hedge mark-to-market gains of $87 million. Unamortized discount is generally being amortized to interest expense on the effective interest method over the lives of the related issuances. At December 31, 2003, under the most restrictive covenants of certain financing agreements, the capacity for the payment of cash dividends and other distributions on, and for acquisitions of, Occidental's capital stock was approximately $5.2 billion, assuming that such dividends, distributions and acquisitions were made without incurring additional borrowings. Occidental estimates the fair value of its long-term debt based on the quoted market prices for the same or similar issues or on the yields offered to Occidental for debt of similar rating and similar remaining maturities. The estimated fair value of Occidental's total debt, including trust preferred securities, at December 31, 2003 and 2002, was approximately $5.0 billion and $5.2 billion, respectively, compared with a carrying value of approximately $4.5 billion, and approximately $4.7 billion, respectively. NOTE 7 LEASE COMMITMENTS -------------------------------------------------------------------------------- The present value of minimum capital lease payments, net of the current portion, totaled $26 million at both December 31, 2003 and 2002. These amounts are included in other liabilities. Operating and capital lease agreements, which include leases for manufacturing facilities, office space, railcars and tanks, frequently include renewal and/or purchase options and require Occidental to pay for utilities, taxes, insurance and maintenance expense. At December 31, 2003, future net minimum lease payments for capital and operating leases (excluding oil and gas and other mineral leases) were the following:
In millions Capital Operating ================================================================================ =========== =========== 2004 $ 1 $ 98 2005 1 86 2006 1 75 2007 1 62 2008 1 59 Thereafter 28 865 ----------- ----------- TOTAL MINIMUM LEASE PAYMENTS 33 $ 1,245 =========== Less: Imputed interest (6) Current portion (1) ----------- PRESENT VALUE OF MINIMUM CAPITAL LEASE PAYMENTS, NET OF CURRENT PORTION $ 26 ================================================================================ ===========
Rental expense for operating leases, net of sublease rental income, was $118 million in 2003, $81 million in 2002 and $84 million in 2001. Rental expense was net of sublease income of $8 million in 2003, $7 million in 2002 and $8 million in 2001. At December 31, 2003, sublease rental amounts included in the future operating lease payments totaled $87 million, as follows (in millions): 2004--$8, 2005--$9, 2006--$9, 2007--$8, 2008--$8 and thereafter--$45. Included in both the 2003 and 2002 property, plant and equipment accounts were $10 million of property leased under capital leases and $8 million and $7 million, respectively, of related accumulated amortization. 50 NOTE 8 ENVIRONMENTAL LIABILITIES AND EXPENDITURES -------------------------------------------------------------------------------- Occidental's operations in the United States are subject to stringent federal, state and local laws and regulations relating to improving or maintaining environmental quality. Foreign operations also are subject to environmental-protection laws. Costs associated with environmental compliance have increased over time and are generally expected to rise in the future. Environmental expenditures related to current operations are factored into the overall business planning process. These expenditures are mainly considered an integral part of production in manufacturing quality products responsive to market demand. The laws that require or address environmental remediation may apply retroactively to past waste disposal practices and releases. In many cases, the laws apply regardless of fault, legality of the original activities or current ownership or control of sites. Occidental Petroleum Corporation (OPC) or certain of its subsidiaries are currently participating in environmental assessments and cleanups under these laws at federal Superfund sites, comparable state sites and other remediation sites, including Occidental facilities and previously owned sites. Also, OPC and certain of its subsidiaries have been involved in a substantial number of governmental and private proceedings involving historical practices at various sites including, in some instances, having been named in proceedings under CERCLA and similar federal, state and local environmental laws. These proceedings seek funding or performance of remediation and, in some cases, compensation for alleged property damage, punitive damages and civil penalties. Occidental manages its environmental remediation efforts through a wholly owned subsidiary, Glenn Springs Holdings, Inc. (GSH), which reports its results directly to Occidental's corporate management. The following table presents Occidental's environmental remediation reserves at December 31, 2003, 2002 and 2001 grouped by three categories of environmental remediation sites:
$ amounts in millions 2003 2002 2001 =============================== ========================== ========================== =========================== RESERVE Reserve Reserve NUMBER OF SITES BALANCE Number of Sites Balance Number of Sites Balance --------------- ------- --------------- ------- --------------- ------- CERCLA & equivalent sites 131 $ 240 124 $ 284 126 $ 320 Active facilities 13 79 14 46 14 59 Closed or sold facilities 39 53 44 63 47 75 --------------- ------- --------------- ------- --------------- ------- TOTAL 183 $ 372 182 $ 393 187 $ 454 =============================== =============== ======= =============== ======= =============== =======
The increase in the number of CERCLA and equivalent sites between 2002 and 2003 was primarily in the "minimal/no exposure" category as discussed below. The following table shows environmental reserve activity for the past three reporting periods:
12 MONTHS 12 Months 12 Months ENDED Ended Ended In millions 12/31/03 12/31/02 12/31/01 =========================================================================== ========== ========== ========== Balance -- Beginning of Year $ 393 $ 454 $ 402 Increases to provision including interest accretion 64 25 111 Changes from acquisitions/dispositions -- -- 5 Payments (83) (84) (75) Other (2) (2) 11 ---------- ---------- ---------- Balance -- End of Year $ 372 $ 393 $ 454 =========================================================================== ========== ========== ==========
Occidental expects to expend funds equivalent to about half of the current environmental reserve over the next three years and the balance over the next ten or more years. Occidental expects that it may continue to incur additional liabilities beyond those recorded for environmental remediation at these and other sites. The range of reasonably possible loss for existing environmental remediation matters could be up to $400 million beyond the amount accrued. For management's opinion, refer to Note 9. 51 At December 31, 2003, OPC or certain of its subsidiaries have been named in 131 CERCLA or state equivalent proceedings, as shown below.
Description ($ amounts in millions) Number of Sites Reserve Balance ====================================================================== =============== =============== Minimal/No exposure (a) 109 $ 5 Reserves between $1-10 MM 15 59 Reserves over $10 MM 7 176 --------------- --------------- TOTAL 131 $ 240 ====================================================================== =============== ===============
(a) Includes 33 sites for which Maxus Energy Corporation has retained the liability and indemnified Occidental, 7 sites where Occidental has denied liability without challenge, 57 sites where Occidental's reserves are less than $50,000 each, and 12 sites where reserves are between $50,000 and $1 million each. The seven sites with individual reserves over $10 million in 2003 are a former copper mining and smelting operation in Tennessee, two closed landfills in Western New York, groundwater treatment facilities at three former chemical plants (Western New York, Montague, Michigan and Tacoma, Washington) and a municipal drinking water treatment plant in Western New York. Certain subsidiaries of OPC are currently addressing releases of substances from past operations at 13 active facilities. Four facilities -- certain oil and gas properties in the southwestern United States, a chemical plant in Louisiana, a chemical plant in Texas and a phosphorous recovery operation in Tennessee -- account for 89 percent of the reserves associated with these facilities. There are 39 sites formerly owned or operated by certain subsidiaries of OPC that have ongoing environmental remediation requirements. Three sites account for 72 percent of the reserves associated with this group. The three sites are: an active refinery in Louisiana where Occidental indemnifies the current owner and operator for certain remedial actions, a water treatment facility at a former coal mine in Pennsylvania, and a former chemical plant in West Virginia. Occidental's costs, some of which may include estimates, relating to compliance with environmental laws and regulations are shown below for each segment:
In millions 2003 2002 2001 ================================================================================ ======== ======== ======== OPERATING EXPENSES Oil and Gas $ 40 $ 32 $ 22 Chemical 49 46 47 -------- -------- -------- $ 89 $ 78 $ 69 ======== ======== ======== CAPITAL EXPENDITURES Oil and Gas $ 98 $ 70 $ 60 Chemical 15 16 20 -------- -------- -------- $ 113 $ 86 $ 80 ======== ======== ======== REMEDIATION EXPENSES Corporate $ 63 $ 23 $ 109 ================================================================================ ======== ======== ========
Operating expenses are incurred on a continual basis. Capital expenditures relate to longer-lived improvements in currently operating facilities. Remediation expenses relate to existing conditions caused by past operations and do not contribute to current or future revenue generation. Although total costs may vary in any one year, over the long term, segment operating and capital expenditures for environmental compliance generally are expected to increase. In October 2001, the federal Environmental Protection Agency (EPA) approved a State Implementation Plan (SIP) for eight counties in the Houston-Galveston area of Texas to implement certain requirements of the federal Clean Air Act. The SIP contains provisions requiring the reduction of 80 percent of nitrogen oxide emissions and 60 percent of certain volatile organic compound emissions by November 2007. Occidental operates six facilities that are subject to the SIP's emissions reduction requirements and estimates that its future capital expenditures will total approximately $25 to $30 million for environmental control and monitoring equipment necessary to comply with the SIP. Occidental expects expenditures to end in 2007, although the timing of the expenditures will vary by facility. 52 NOTE 9 LAWSUITS, CLAIMS, COMMITMENTS, CONTINGENCIES AND RELATED MATTERS -------------------------------------------------------------------------------- OPC and certain of its subsidiaries have been named in a substantial number of lawsuits, claims and other legal proceedings. These actions seek, among other things, compensation for alleged personal injury, breach of contract, property damage, punitive damages, civil penalties or other losses; or injunctive or declaratory relief. OPC and certain of its subsidiaries also have been named in proceedings under CERCLA and similar federal, state and local environmental laws. These environmental proceedings seek funding or performance of remediation and, in some cases, compensation for alleged property damage, punitive damages and civil penalties; however, Occidental is usually one of many companies in these proceedings and has to date been successful in sharing response costs with other financially sound companies. With respect to all such lawsuits, claims and proceedings, including environmental proceedings, Occidental accrues reserves when it is probable a liability has been incurred and the amount of loss can be reasonably estimated. During the course of its operations, Occidental is subject to audit by tax authorities for varying periods in various federal, state, local and foreign tax jurisdictions. Taxable years prior to 1997 are closed for U.S. federal income tax purposes. Taxable years 1997 through 2002 are in various stages of audit by the Internal Revenue Service. Disputes arise during the course of such audits as to facts and matters of law. At December 31, 2003, commitments for major capital expenditures during 2004 and thereafter were approximately $201 million. Occidental has entered into agreements providing for future payments to secure terminal and pipeline capacity, drilling services, electrical power, steam and certain chemical raw materials. At December 31, 2003, the net present value of the fixed and determinable portion of the obligations under these agreements, which were used to collateralize financings of the respective suppliers, aggregated $45 million, which was payable as follows (in millions): 2004--$12, 2005--$11, 2006--$10, 2007--$9 and 2008--$3. Fixed payments under these agreements were $16 million in 2003, $27 million in 2002 and $20 million in 2001. Occidental has certain other commitments under contracts, guarantees and joint ventures, and certain other contingent liabilities. Many of these commitments, although not fixed or determinable, involve capital expenditures and are part of the $1.4 billion capital expenditures estimated for 2004, and the $250 to $300 million estimated to be spent on the Dolphin Project in 2004. As discussed in Note 4, FIN 45 requires the disclosure in Occidental's financial statements of information relating to guarantees issued by Occidental and outstanding at December 31, 2003. These guarantees encompass performance bonds, letters of credit, indemnities, commitments and other forms of guarantees provided by Occidental to third parties, mainly to provide assurance that Occidental and/or its subsidiaries and affiliates will meet their various obligations (guarantees). At December 31, 2003, the notional amount of the guarantees was approximately $500 million. Of this amount, approximately $400 million relates to Occidental's guarantee of equity investees' debt and other commitments. The debt guarantees relating to Elk Hills Power and the guarantees on debt and other commitments relating to the Ecuador pipeline. The remaining $100 million relates to various indemnities and guarantees provided to third parties. Occidental has indemnified various parties against specified liabilities that those parties might incur in the future in connection with purchases and other transactions that they have entered into with Occidental. These indemnities usually are contingent upon the other party incurring liabilities that reach specified thresholds. As of December 31, 2003, Occidental is not aware of circumstances that would lead to future indemnity claims against it for material amounts in connection with these transactions. It is impossible at this time to determine the ultimate liabilities that OPC and its subsidiaries may incur resulting from any lawsuits, claims and proceedings, audits, commitments, contingencies and related matters. If these matters were to be ultimately resolved unfavorably at amounts substantially exceeding Occidental's reserves, an outcome not currently anticipated, it is possible that such outcome could have a material adverse effect upon Occidental's consolidated financial position or results of operations. However, after taking into account reserves, management does not expect the ultimate resolution of any of these matters to have a material adverse effect upon Occidental's consolidated financial position or results of operations. 53 NOTE 10 DOMESTIC AND FOREIGN INCOME AND OTHER TAXES -------------------------------------------------------------------------------- The domestic and foreign components of income from continuing operations before domestic and foreign income and other taxes were as follows:
For the years ended December 31, (in millions) Domestic Foreign Total =========================================================================== ========== ========== ========== 2003 $ 1,506 $ 1,316 $ 2,822 ========== ========== ========== 2002 $ 438 $ 1,147 $ 1,585 ========== ========== ========== 2001 $ 272 $ 1,463 $ 1,735 =========================================================================== ========== ========== ==========
The provisions(credits) for domestic and foreign income and other taxes from continuing operations consisted of the following:
U.S. State For the years ended December 31, (in millions) Federal and Local Foreign Total ================================================================= ========== ========== ========== ========== 2003 Current $ 564 $ 29 $ 573 $ 1,166 Deferred 82 (6) (15) 61 ---------- ---------- ---------- ---------- $ 646 $ 23 $ 558 $ 1,227 ================================================================= ========== ========== ========== ========== 2002 Current $ 79 $ 9 $ 475 $ 563 Deferred (112) (26) (3) (141) ---------- ---------- ---------- ---------- $ (33) $ (17) $ 472 $ 422 ================================================================= ========== ========== ========== ========== 2001 Current $ 326 $ 17 $ 396 $ 739 Deferred (40) (141) (2) (183) ---------- ---------- ---------- ---------- $ 286 $ (124) $ 394 $ 556 ================================================================= ========== ========== ========== ==========
The credit for deferred federal and state and local income taxes in 2002 results primarily from the sale of the investment in Equistar. The credit for deferred state and local income taxes in 2001 reflects a benefit of $70 million related to the settlement of a state tax issue, deferred tax reversing due to the sale of the entity owning pipelines in Texas that were leased to a former subsidiary, a write-down of the investment in Equistar and an adjustment to reflect lower effective state tax rates. The following is a reconciliation, stated as a percentage of pre-tax income, of the U.S. statutory federal income tax rate to Occidental's effective tax rate on income from continuing operations:
For the years ended December 31, 2003 2002 2001 =========================================================================== ======== ======== ======== U.S. federal statutory tax rate 35 % 35 % 35 % Operations outside the United States (a) 8 12 2 Benefit from sale of subsidiary stock -- (21) -- State taxes, net of federal benefit 1 -- (5) Other (1) 1 -- -------- -------- -------- Tax rate provided by Occidental 43 % 27 % 32 % =========================================================================== ======== ======== ========
(a) Included in these figures is the impact of not providing U.S. taxes on the unremitted earnings of certain foreign subsidiaries. The effect of this is to reduce the U.S. federal tax rate by approximately 5 percent in 2003 and 7 percent in 2002. The effect on 2001 was insignificant due to distributions from these subsidiaries. 54 The tax effects of temporary differences resulting in deferred income taxes at December 31, 2003 and 2002 were as follows:
2003 2002 ------------------------- ------------------------- DEFERRED DEFERRED Deferred Deferred TAX TAX Tax Tax Items resulting in temporary differences (in millions) ASSETS LIABILITIES Assets Liabilities ====================================================================== =========== =========== =========== =========== Property, plant and equipment differences $ 79 $ 1,317 $ 87 $ 1,166 Equity investments including partnerships -- 365 -- 375 Environmental reserves 163 -- 155 -- Postretirement benefit accruals 127 -- 129 -- Deferred compensation and fringe benefits 144 -- 135 -- Asset retirement obligation 58 -- -- -- State income taxes 44 -- 41 -- All other 224 83 186 60 ----------- ----------- ----------- ----------- Total deferred taxes $ 839 $ 1,765 $ 733 $ 1,601 ====================================================================== =========== =========== =========== ===========
Included in total deferred tax assets was a current portion aggregating $75 million and $114 million as of December 31, 2003 and 2002, respectively, that was reported in prepaid expenses and other. A deferred tax liability of approximately $210 million at December 31, 2003 has not been recognized for temporary differences related to Occidental's investment in certain foreign subsidiaries primarily as a result of unremitted earnings of consolidated subsidiaries, as it is Occidental's intention, generally, to reinvest such earnings permanently. The discontinued operations include an income tax benefit of $18 million in 2002 and an income tax expense of $3 million in 2001. The cumulative effect of changes in accounting principles was reduced by an income tax benefit of $38 million in 2003 and $6 million in 2002. Additional paid-in capital was credited $30 million in 2003 and $7 million in 2002 for a tax benefit resulting from the exercise of certain stock options. NOTE 11 STOCKHOLDERS' EQUITY -------------------------------------------------------------------------------- The following is an analysis of common stock:
(shares in thousands) Common Stock ================================================================================ ============== Balance, December 31, 2000 369,984 Issued 1,064 Options exercised and other, net 3,078 -------------------------------------------------------------------------------- -------------- Balance, December 31, 2001 374,126 Issued 1,027 Options exercised and other, net 2,707 -------------------------------------------------------------------------------- -------------- Balance, December 31, 2002 377,860 Issued 1,156 Options exercised and other, net 8,032 -------------------------------------------------------------------------------- -------------- BALANCE, DECEMBER 31, 2003 387,048 ================================================================================ ==============
55 NONREDEEMABLE PREFERRED STOCK Occidental has authorized 50,000,000 shares of preferred stock with a par value of $1.00 per share. At December 31, 2003, 2002 and 2001, Occidental had no outstanding shares of preferred stock. EARNINGS PER SHARE AND ANTI-DILUTIVE COMPUTATIONS Basic earnings per share was computed by dividing net income plus the effect of repurchase of trust preferred securities by the weighted average number of common shares outstanding during each year. The computation of diluted earnings per share further assumes the dilutive effect of stock options. The following are the share amounts used to compute the basic and diluted earnings per share for the years ended December 31:
In millions 2003 2002 2001 =========================================================================== ========== ========== ========== BASIC EARNINGS PER SHARE Basic Shares Outstanding 383.9 376.2 372.1 ========== ========== ========== DILUTED EARNINGS PER SHARE Basic shares outstanding 383.9 376.2 372.1 Dilutive effect of exercise of options outstanding 3.9 2.7 1.8 Other .8 .6 .4 ---------- ---------- ---------- Dilutive Shares 388.6 379.5 374.3 =========================================================================== ========== ========== ==========
The following items were not included in the computation of diluted earnings per share because their effect was anti-dilutive for the years ended December 31:
2003 2002 2001 =================================================================== ================ ================ ================ STOCK OPTIONS Number of anti-dilutive options (in millions) NONE 0.02 0.02 Price range -- $29.063-$29.438 $29.063-$29.438 Expiration range -- 12/1/07-4/29/08 12/1/07-4/29/08 ------------------------------------------------------------------- ---------------- ---------------- ----------------
ACCUMULATED OTHER COMPREHENSIVE INCOME (AOCI) AOCI consisted of the following:
Balance at December 31, (in millions) 2003 2002 ================================================================================ ========== ========== Foreign currency translation adjustments $ (18) $ (56) Derivative mark-to-market adjustments (24) (26) Minimum pension liability adjustments 3 (10) Unrealized gains on securities 89 65 ---------- ---------- TOTAL $ 50 $ (27) ================================================================================ ========== ==========
NOTE 12 STOCK INCENTIVE PLANS -------------------------------------------------------------------------------- Occidental applies APB No. 25 and related interpretations in accounting for its stock incentive plans (Plans), which are described below. The pro-forma effect on net income and earnings per share, had Occidental applied the fair-value recognition provisions of SFAS No. 123, are shown in Note 1. The company has established several stock incentive plans offering certain employees and management stock options, restricted stock, stock appreciation rights and performance stock awards. These awards are granted under the 1995 and 2001 Incentive Stock Plans. The 1995 Plan was terminated, for the purposes of further award grants, upon the effective date of the 2001 Plan; however, certain 1995 Plan award grants are outstanding at December 31, 2003. An aggregate of 27,000,000 share-based awards are reserved for issuance under the 2001 Plan and at December 31, 2003, approximately 7,574,285 share-based awards were available for future awards. The company has also established the 1996 Restricted Stock Plan for non-employee directors, where non-employee directors receive awards of restricted stock as additional compensation for their services as members of the Board of Directors. A maximum of 150,000 shares of stock may be awarded under the Directors Plan and at December 31, 2003, 34,572 shares of common stock were available for future grants. 56 STOCK OPTION PLANS Under the stock option plans, certain employees and executives are granted stock options with an exercise price equal to the fair value of the company's stock on the date of grant. Generally, the options vest over three years with a maximum term of ten years and one month. Under certain conditions, the option awards are forfeitable. The following is a summary of stock option transactions during 2003, 2002 and 2001:
2003 2002 2001 ------------------------ ------------------------ ------------------------ WEIGHTED Weighted Weighted AVERAGE Average Average (shares in thousands) OPTIONS EXERCISE PRICE Options Exercise Price Options Exercise Price ===================================== ======= ============== ======= ============== ======= ============== BEGINNING BALANCE 26,972 $ 24.22 25,390 $ 23.40 18,217 $ 21.53 Granted or issued 5,191 $ 31.13 4,904 $ 26.43 11,039 $ 26.17 Exercised (8,999) $ 22.30 (3,097) $ 21.12 (3,395) $ 22.40 Forfeited or expired (152) $ 24.96 (225) $ 22.52 (471) $ 23.50 ------- ------- ------- ENDING BALANCE 23,012 $ 26.53 26,972 $ 24.22 25,390 $ 23.40 OPTIONS EXERCISABLE AT YEAR END 12,535 $ 24.62 16,186 $ 23.33 15,023 $ 22.95 ------------------------------------- ------- -------------- ------- -------------- ------- --------------
The following is a summary of stock options outstanding at December 31, 2003:
OPTIONS OUTSTANDING OPTIONS EXERCISABLE ------------------------------------- ------------------------------------- WEIGHTED WEIGHTED WEIGHTED AVERAGE AVERAGE AVERAGE RANGE OF REMAINING EXERCISE EXERCISE EXERCISE PRICES OUTSTANDING CONTRACTUAL LIFE PRICE EXERCISABLE PRICE ================ ============ ================ ================ ================ ================ $14.88 -- $21.88 2,883,228 6.1 $ 20.37 2,883,228 $ 20.37 $23.13 -- $26.43 9,945,531 5.7 $ 25.80 6,712,650 $ 25.50 $26.75 -- $31.13 10,183,164 8.5 $ 29.06 2,939,602 $ 26.76 ---------------- ------------ ---------------- ---------------- ---------------- ---------------- $14.88 -- $31.13 23,011,923 7.0 $ 26.53 12,535,480 $ 24.62 ---------------- ------------ ---------------- ---------------- ---------------- ----------------
RESTRICTED AND PERFORMANCE STOCK PLANS RESTRICTED STOCK PLANS Under the restricted stock plans, certain executives are awarded restricted common stock and the right to receive shares (Share Units). The restricted stock and Share Units vest between three and five years and are forfeitable under certain conditions. The Share Units are generally deferred until retirement. Restricted stock is issued when awarded and is included in both basic and diluted shares outstanding, while the unvested Share Units are included only in the diluted shares outstanding. The unvested restricted stock is included in diluted shares outstanding. PERFORMANCE STOCK PLANS Under the performance stock plans, the number of common shares issued at the end of the performance period of four years will depend upon the attainment of certain performance objectives, and ranges from 0 to 200 percent of the target share award. As the amount of expected award is dependent upon actual performance, these performance awards are variable under APB No. 25 and changes to the expected award are reflected in income. As the unvested performance stock awards are contingently issuable shares, they are not included in the computation of diluted earnings per share calculation. The number and weighted average grant date value of restricted stock, share units and performance stock awards were as follows:
2003 2002 2001 =========================================================================== ========== ========== ========== Restricted stock, share units and performance stock (a) 1,125,612 1,261,421 633,026 Weighted average fair value $ 31.86 $ 26.74 $ 24.51 --------------------------------------------------------------------------- ---------- ---------- ----------
(a) Performance stock award grants assume a 100-percent payout on the date of grant. 57 NOTE 13 RETIREMENT PLANS AND POSTRETIREMENT BENEFITS -------------------------------------------------------------------------------- Occidental has various defined benefit and defined contribution retirement plans for its salaried, domestic union and nonunion hourly, and certain foreign national employees. Participation in the defined benefit plans is limited and approximately 1,400 domestic and 500 foreign national employees, mainly union, non-union hourly and certain acquired employees with grandfathered benefits, are currently accruing benefits under these plans. All domestic employees and certain foreign national employees are eligible to participate in one or more of the defined contribution retirement or savings plans that provide for periodic contributions by Occidental based on plan-specific criteria, such as base pay, age level, and/or employee contributions. Certain salaried employees participate in a supplemental retirement plan that provides restoration of benefits lost due to governmental limitations on qualified retirement benefits. The accrued liabilities for the supplemental retirement plan were $55 million, $52 million and $42 million as of December 31, 2003, 2002 and 2001, respectively, and Occidental expensed $59 million in 2003, $57 million in 2002 and $57 million in 2001 under the provisions of these defined contribution and supplemental retirement plans. Occidental provides medical and dental benefits and life insurance coverage for certain active, retired and disabled employees and their eligible dependents. The benefits generally are funded by Occidental as the benefits are paid during the year. The cost of providing these benefits is based on claims filed and insurance premiums paid for the period. The total benefit costs including the postretirement costs were approximately $94 million in 2003, $91 million in 2002 and $82 million in 2001. Pension costs for Occidental's defined benefit pension plans, determined by independent actuarial valuations, are generally funded by payments to trust funds, which are administered by independent trustees. A December 31 measurement date is used for all defined pension and postretirement benefit plans. In 2002, a 401(h) account was established within one of Occidental's defined benefit pension plans. This plan allows Occidental to fund postretirement medical benefits for employees at one of its operations. Contributions to this 401(h) account are made at Occidental's discretion. All of Occidental's other postretirement benefit plans are unfunded. The following table sets forth the components of the net periodic benefit costs for Occidental's defined benefit pension and postretirement benefit plans for 2003, 2002, and 2001:
Pension Benefits Postretirement Benefits ------------------------ -------------------------------------------- Unfunded Plans Funded Plans ------------------------ --------------- For the years ended December 31, (in millions) 2003 2002 2001 2003 2002 2001 2003 2002 ==================================================== ====== ====== ====== ====== ====== ====== ====== ====== NET PERIODIC BENEFIT COSTS: Service cost -- benefits earned during the period $ 13 $ 10 $ 9 $ 6 $ 6 $ 5 $ 1 $ -- Interest cost on benefit obligation 23 26 25 33 33 31 1 1 Expected return on plan assets (20) (20) (24) -- -- -- -- -- Amortization of net transition obligation -- -- -- -- -- -- -- -- Amortization of prior service cost 1 1 1 1 -- -- -- -- Recognized actuarial loss 3 1 4 8 6 -- -- -- Curtailments and settlements -- 1 -- -- -- -- -- -- Currency adjustments 2 (8) (1) -- -- -- -- -- ------ ------ ------ ------ ------ ------ ------ ------ Net periodic benefit cost $ 22 $ 11 $ 14 $ 48 $ 45 $ 36 $ 2 $ 1 ==================================================== ====== ====== ====== ====== ====== ====== ====== ======
Occidental recorded a credit to accumulated other comprehensive income of $13 million in 2003, a charge of $5 million in 2002 and a credit of $6 million in 2001, to reflect the net-of-tax difference between the additional liability required under pension accounting provisions and the corresponding intangible asset. The change in accumulated other comprehensive income in 2003 reflected an actual return on plan assets that was greater than the expected return on plan assets and an additional pension contribution of $18 million in 2003, partially offset by a decrease in the discount rate. Occidental's defined benefit pension and postretirement defined benefit plans are accrued based on various assumptions and discount rates, as described below. Occidental uses the fair value of assets to determine pension expense. Occidental funds and expenses negotiated pension increases for domestic union employees over the term of the collective bargaining agreement. The actuarial assumptions used could change in the near term as a result of changes in expected future trends and other factors that, depending on the nature of the changes, could cause increases or decreases in the plan liabilities accrued. 58 The following table sets forth the reconciliation of the beginning and ending balances of the benefit obligation for Occidental's defined benefit pension and postretirement benefit plans:
Pension Benefits Postretirement Benefits ---------------- ------------------------------------- Unfunded Plans Funded Plans ---------------- ---------------- For the years ended December 31, (in millions) 2003 2002 2003 2002 2003 2002 ============================================================ ====== ====== ====== ====== ====== ====== CHANGES IN BENEFIT OBLIGATION: Benefit obligation -- beginning of year $ 357 $ 337 $ 501 $ 453 $ 14 $ 12 Service cost -- benefits earned during the period 13 10 6 6 1 -- Interest cost on projected benefit obligation 23 26 33 33 1 1 Actuarial loss 19 10 52 59 4 2 Foreign currency exchange rate changes 3 (11) -- -- -- -- Benefits paid (22) (21) (48) (50) (1) (1) Plan amendments (1) 2 -- -- -- -- Cost recovery percentage -- 6 -- -- -- -- Divestitures -- (3) -- -- -- -- Special termination benefits -- 1 -- -- -- -- ------ ------ ------ ------ ------ ------ Benefit obligation -- end of year $ 392 $ 357 $ 544 $ 501 $ 19 $ 14 ============================================================ ====== ====== ====== ====== ====== ======
The following table sets forth the reconciliation of the beginning and ending balances of the fair value of plan assets for Occidental's defined benefit pension and postretirement benefit plans:
Pension Benefits Postretirement Benefits ---------------- ------------------------- Funded Plans ------------------------- For the years ended December 31, (in millions) 2003 2002 2003 2002 ============================================================ ====== ====== ========== ========== CHANGES IN PLAN ASSETS: Fair value of plan assets -- beginning of year $ 251 $ 255 $ -- $ -- Actual return on plan assets 48 (1) -- -- Foreign currency exchange rate changes 1 (3) -- -- Employer contribution 31 23 2 1 Benefits paid (22) (21) (1) (1) Divestitures -- (2) -- -- ------ ------ ---------- ---------- Fair value of plan assets -- end of year $ 309 $ 251 $ 1 $ -- ============================================================ ====== ====== ========== ==========
The following table sets forth the asset allocation of Occidental's domestic defined benefit pension and funded postretirement benefit plans at December 31, 2003 and 2002.
Pension Benefits Postretirement Benefits ---------------- ------------------------- Funded Plans ------------------------- For the years ended December 31, 2003 2002 2003 2002 ============================================================ ====== ====== ========== ========== ASSET CATEGORY: Equity securities 61 % 55 % -- % -- % Debt securities 39 45 100 100 ------ ------ ---------- ---------- Total 100 % 100 % 100 % 100 % ============================================================ ====== ====== ========== ==========
Occidental employs a total return investment approach whereby a mix of equity and fixed income investments is used to maximize the long-term return of plan assets at a prudent level of risk. The investments are monitored by Occidental's Investment Committee in its role as fiduciary. The Investment Committee, consisting of senior executives of the company, selects and employs various external professional investment management firms to manage specific assignments across the spectrum of asset classes. The resulting aggregate investment portfolio contains a diversified blend of equity and fixed-income investments. Furthermore, equity investments are diversified across U.S. and non-U.S. stocks, as well as differing styles and market capitalizations. Other asset classes such as private equity and real estate may be used to enhance long-term returns while improving portfolio diversification. Investment performance is measured and monitored on an ongoing basis through quarterly investment and manager guideline compliance reviews, annual liability measurements, and periodic studies. 59 The projected benefit obligation, accumulated benefit obligation and fair value of plan assets for defined benefit pension plans with accumulated benefit obligation in excess of plan assets were $184 million, $166 million and $96 million, respectively, as of December 31, 2003 and $231 million, $211 million and $124 million, respectively, as of December 31, 2002. The projected benefit obligation, accumulated benefit obligation and fair value of plan assets for defined benefit pension plans with plan assets in excess of accumulated benefit obligation were $208 million, $205 million, and $213 million respectively, as of December 31, 2003 and $126 million, $126 million, and $127 million, respectively, as of December 31, 2002. The following table sets forth the weighted average assumptions used to determine Occidental's domestic benefit obligation and net periodic benefit cost for domestic plans:
Pension Benefits Postretirement Benefits ---------------- ------------------------------------- Unfunded Plans Funded Plans ---------------- ---------------- For the years ended December 31, 2003 2002 2003 2002 2003 2002 ============================================================ ====== ====== ====== ====== ====== ====== BENEFIT OBLIGATIONS: Discount rate 6.00% 6.65% 6.00% 6.65% 6.00% 6.65% Rate of compensation increase 4.00 4.00 -- -- -- -- NET PERIODIC BENEFIT COST: Discount rate 6.65% 7.00% 6.65% 7.00% 6.65% 7.00% Expected long term rate of return on assets 8.00 8.00 -- -- 8.00 -- Rate of compensation increase 4.00 4.50 -- -- -- -- ------------------------------------------------------------ ------ ------ ------ ------ ------ ------
For domestic pension plans, Occidental bases the discount rate on the average yield provided by the Moody's Aa Corporate Bond Index. The weighted average rate of increase in future compensation levels is consistent with Occidental's past and anticipated future compensation increases for employees participating in retirement plans that determine benefits using compensation. The long-term rate of return on assets assumption is established with regard to current market factors but within the context of historical returns. Historical returns and correlation of equities and fixed income securities are studied. Current market factors such as inflation and interest rates are also evaluated. For pension plans outside of the United States, the assumptions used in determining the benefit obligation vary by country. The discount rates used in determining the benefit obligation ranged from a low of 4 percent to a high of 13 percent at both December 31, 2003 and 2002. Occidental bases its discount rate for foreign pension plans on rates indicative of government and or investment grade corporate debt in the applicable country. The average rate of increase in future compensation levels ranged from a low of 3 percent to a high of 8 percent in 2003 and from a low of 3 percent to a high of 9 percent in 2002, dependent on local economic conditions and salary budgets. The expected long-term rate of return on plan assets was 5.5 percent in excess of local inflation in both 2003 and 2002. The postretirement benefit obligation was determined by application of the terms of medical and dental benefits and life insurance coverage, including the effect of established maximums on covered costs, together with relevant actuarial assumptions and health care cost trend rates projected at a Consumer Price Index (CPI) increase of 3.0 percent as of December 31, 2003 and 2002, (beginning in 1993, participants other than certain union employees pay for all medical cost increases in excess of increases in the CPI). For certain union employees, the health care cost trend rates were projected at annual rates ranging ratably from 10 percent in 2003 to 6 percent through the year 2007 and level thereafter. A 1-percent increase or a 1-percent decrease in these assumed health care cost trend rates would result in an increase of $16 million or a reduction of $15 million, respectively, in the postretirement benefit obligation as of December 31, 2003, and an increase or reduction of $1 million in interest cost in 2003. The annual service costs would not be materially affected by these changes. On December 8, 2003, President Bush signed into law a bill that expands Medicare, primarily adding a prescription drug benefit for Medicare-eligible retirees starting in 2006. Occidental intends to review its retirees' health care plans in light of the new Medicare provisions, which may change Occidental's obligations under the plan. Therefore, the retiree medical obligations and costs reported do not reflect the impact of this legislation. Deferring the recognition of the new Medicare provisions' impact is permitted by Financial Accounting Standards Board Staff Position 106-1 due to open questions about some of the new Medicare provisions and a lack of authoritative accounting guidance about certain matters. The final accounting guidance could require changes to previously reported information. Occidental expects to contribute $6 million to its domestic defined benefit pension plans during 2004. All of the contributions are expected to be in the form of cash. 60 The following table sets forth the funded status and amounts recognized in Occidental's consolidated balance sheets for the defined benefit pension and postretirement benefit plans at December 31, 2003 and 2002:
Pension Benefits Postretirement Benefits ---------------- ------------------------------------- Unfunded Plans Funded Plans ---------------- ---------------- For the years ended December 31, (in millions) 2003 2002 2003 2002 2003 2002 ============================================================ ====== ====== ====== ====== ====== ====== Unfunded obligation $ (83) $ (106) $ (544) $ (501) $ (18) $ (14) Unrecognized prior service cost 4 6 8 9 -- -- Unrecognized net loss 64 76 170 125 8 5 ------ ------ ------ ------ ------ ------ Net amount recognized $ (15) $ (24) $ (366) $ (367) $ (10) $ (9) ====== ====== ====== ====== ====== ====== Prepaid benefit cost $ 66 $ 49 $ -- $ -- $ -- $ -- Accrued benefit liability (81) (96) (366) (367) (10) (9) Intangible assets -- 1 -- -- -- -- Accumulated other comprehensive income -- 22 -- -- -- -- ------ ------ ------ ------ ------ ------ Net amount recognized $ (15) $ (24) $ (366) $ (367) $ (10) $ (9) ============================================================ ====== ====== ====== ====== ====== ======
NOTE 14 INVESTMENTS AND RELATED-PARTY TRANSACTIONS -------------------------------------------------------------------------------- EQUITY INVESTMENTS At December 31, 2003, Occidental's equity investments consisted of a 22-percent interest in Lyondell acquired in August 2002, a 24.5-percent interest in the entity that will own the pipeline being constructed by Dolphin Energy, the operator of the Dolphin Project, and other various partnerships and joint ventures, discussed below. Equity investments paid dividends of $81 million, $22 million and $27 million to Occidental in 2003, 2002 and 2001, respectively. Cumulative undistributed earnings since acquisition, in the amount of $55 million, of 50-percent-or-less-owned companies have been accounted for by Occidental under the equity method. At December 31, 2003, Occidental's investments in unconsolidated entities exceeded the underlying equity in net assets by $471 million, of which $356 million represents goodwill that will not be amortized and $115 million represents intangible assets, which will be amortized over the life of the underlying lease of the assets, when placed into service. In October 2003, Occidental purchased an additional 2.7 million shares of Lyondell common stock for $12.40 a share, totaling approximately $33 million. At December 31, 2003, Occidental owned 22 percent (39.5 million shares) of Lyondell stock. The following table presents Occidental's percentage interest in the summarized financial information of its equity method investments:
For the years ended December 31, (in millions) 2003 2002 2001 ================================================================================ ========== ========== ========== Revenues $ 1,179 $ 1,782 $ 2,223 Costs and expenses 1,188 2,043 2,315 ---------- ---------- ---------- Net loss $ (9) $ (261) $ (92) ================================================================================ ========== ========== ========== Balance at December 31, 2003 2002 ================================================================================ ========== ========== Current assets $ 349 $ 421 Non-current assets $ 1,691 $ 1,946 Current liabilities $ 407 $ 225 Long-term debt $ 960 $ 1,458 Other non-current liabilities $ 377 $ 404 Stockholders' equity $ 365 $ 280 -------------------------------------------------------------------------------- ---------- ----------
In Ecuador, Occidental has a 14-percent interest in the Oleoducto de Crudos Pesados (OCP) Ltd. oil export pipeline. Occidental made capital contributions of $64 million in 2003 and as of December 31, 2003, has contributed a total of $73 million to the project. Occidental reports this investment in its consolidated statements using the equity method of accounting. 61 The project was funded in part by senior project debt. The senior project debt is to be repaid with the proceeds of ship-or-pay tariffs of certain upstream producers in Ecuador, including Occidental. Under their ship-or-pay commitments, Occidental and the other upstream producers have each assumed their respective share of project-specific risks, including operating risk and force-majeure risk. Occidental would be required to make an advance tariff payment in the event of prolonged force majeure, upstream expropriation events, bankruptcy of the pipeline company or its parent company, abandonment of the project, termination of an investment guarantee agreement with Ecuador, or certain defaults by Occidental. This advance tariff would be used by the pipeline company to service or prepay project debt. Occidental's obligation relating to the pipeline company's senior project debt totaled $108 million, and Occidental's obligations relating to performance bonds totaled $14 million at December 31, 2003. As Occidental ships product using the pipeline, its overall obligations will decrease with the reduction of the pipeline company's senior project debt. Occidental has a 50-percent interest in Elk Hills Power LLC (EHP), a limited liability company that operates a gas-fired, power-generation plant in California. EHP is a VIE under the provisions of FIN 46. Occidental has concluded it is not the primary beneficiary of EHP and, therefore, accounts for this investment using the equity method. In January 2002, EHP entered into a $400 million construction loan facility, which was amended in May 2003 to increase the facility to $425 million. Upon construction completion on July 17, 2003, the facility converted to a $415 million term loan, 50 percent of which is guaranteed by Occidental. AVAILABLE-FOR-SALE SECURITIES Investments in unconsolidated entities also include Occidental's investment in Premcor, Inc., which became a publicly traded company in April 2002. Occidental accounts for its investment in Premcor as available for sale and this investment is carried at fair value. Prior to becoming public, Occidental carried its investment in Premcor at cost. As of December 31, 2003 and 2002, the fair value of the investment in Premcor was $235 million and $172 million, respectively, with cumulative unrealized after-tax gains of $89 million and $65 million, respectively, in OCI. RELATED-PARTY TRANSACTIONS During 2003, 2002 and 2001, Occidental entered into the following transactions and amounts due from/to with its related parties and had the following amounts outstanding:
For the years ended December 31, (in millions) 2003 2002 2001 =========================================================================== ========== ========== ========== Purchases $ 707 $ 604 $ 660 Sales 502 284 252 Services 1 7 7 Amounts due from 34 43 14 Amounts due to 21 70 35 --------------------------------------------------------------------------- ---------- ---------- ----------
NOTE 15 INDUSTRY SEGMENTS AND GEOGRAPHIC AREAS -------------------------------------------------------------------------------- In compliance with the provisions of SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information," Occidental has identified two reportable segments through which it conducts its continuing operations: oil and gas and chemical. The factors for determining the reportable segments were based on the distinct nature of their operations. They are managed as separate business units because each requires and is responsible for executing a unique business strategy. The oil and gas segment explores for, develops, produces and markets crude oil and natural gas domestically and internationally. The chemical segment manufactures and markets, domestically and internationally, basic chemicals, vinyls and performance chemicals. Earnings of industry segments and geographic areas exclude interest income, interest expense, environmental remediation expenses, unallocated corporate expenses, discontinued operations and cumulative effect of changes in accounting principles, but include income from equity investments (except as noted below) and gains and losses from dispositions of segment and geographic area assets. Foreign income and other taxes and certain state taxes are included in segment earnings on the basis of operating results. U.S. federal income taxes are not allocated to segments except for amounts in lieu thereof that represent the tax effect of operating charges resulting from purchase accounting adjustments, which arose from the implementation in 1992 of SFAS No. 109, "Accounting for Income Taxes," and the tax effects resulting from major, infrequently occurring transactions such as asset sales and legal settlements that relate to segment results. Identifiable assets are those assets used in the operations of the segments. Corporate and other assets consist of cash, short-term investments, certain corporate receivables, a 22-percent equity investment in Lyondell, a 12-percent ownership interest in Premcor, Inc. and the leased co-generation facility in Taft, Louisiana. 62 INDUSTRY SEGMENTS In millions
Corporate Oil and Gas Chemical and Other Total ============================================================= =========== =========== =========== =========== YEAR ENDED DECEMBER 31, 2003 Net sales $ 6,003 (a) $ 3,178 (b) $ 145 (i) $ 9,326 =========== =========== =========== =========== Pretax operating profit(loss) $ 3,229 $ 213 $ (620)(d) $ 2,822 Income taxes (565) (3) (659)(e) (1,227) Discontinued operations, net -- -- -- -- Cumulative effect of changes in accounting principles, net -- -- (68) (68) ----------- ----------- ----------- ----------- Net income(loss) (c) $ 2,664 $ 210 $ (1,347)(g) $ 1,527 =========== =========== =========== =========== Unconsolidated equity investments $ 571 $ 61 $ 523 $ 1,155 =========== =========== =========== =========== Property, plant and equipment additions, net (h) $ 1,237 $ 345 $ 19 $ 1,601 =========== =========== =========== =========== Depreciation, depletion and amortization $ 957 $ 205 $ 15 $ 1,177 =========== =========== =========== =========== Total assets $ 13,274 $ 3,512 $ 1,382 $ 18,168 ============================================================= =========== =========== =========== =========== YEAR ENDED DECEMBER 31, 2002 Net sales $ 4,634 (a) $ 2,704 (b) $ -- $ 7,338 =========== =========== =========== =========== Pretax operating profit(loss) $ 2,181 $ (128) $ (468)(d) $ 1,585 Income taxes (474) 403 (351)(e) (422) Discontinued operations, net -- -- (79) (79) Cumulative effect of changes in accounting principles, net -- -- (95) (95) ----------- ----------- ----------- ----------- Net income(loss) (c, f) $ 1,707 $ 275 $ (993)(g) $ 989 =========== =========== =========== =========== Unconsolidated equity investments $ 475 $ (11) $ 592 $ 1,056 =========== =========== =========== =========== Property, plant and equipment additions, net (h) $ 1,038 $ 109 $ 89 $ 1,236 =========== =========== =========== =========== Depreciation, depletion and amortization $ 819 $ 183 $ 10 $ 1,012 =========== =========== =========== =========== Total assets $ 12,407 $ 3,069 $ 1,072 $ 16,548 ============================================================= =========== =========== =========== =========== YEAR ENDED DECEMBER 31, 2001 Net sales $ 5,134 (a) $ 2,968 (b) $ -- $ 8,102 =========== =========== =========== =========== Pretax operating profit(loss) $ 3,292 $ (442) $ (1,115)(d) $ 1,735 Income taxes (447) 43 (152)(e) (556) Discontinued operations, net -- -- (1) (1) Cumulative effect of changes in accounting principles, net -- -- (24) (24) ----------- ----------- ----------- ----------- Net income(loss) (c, f) $ 2,845 $ (399) $ (1,292)(g) $ 1,154 =========== =========== =========== =========== Unconsolidated equity investments $ 75 $ 663 $ 255 $ 993 =========== =========== =========== =========== Property, plant and equipment additions, net (h) $ 1,138 $ 112 $ 58 $ 1,308 =========== =========== =========== =========== Depreciation, depletion and amortization $ 750 $ 184 $ 31 $ 965 =========== =========== =========== =========== Total assets $ 13,316 $ 3,943 $ 591 $ 17,850 ============================================================= =========== =========== =========== ===========
Footnotes: ---------- (a) Oil sales represented approximately 74 percent, 77 percent and 60 percent of net oil and gas sales for the periods ended December 31, 2003, 2002 and 2001, respectively. (b) Total product sales for the chemical segment were as follows:
Basic Chemicals Commodity Vinyl Resins Performance Chemicals ====================== ====================== ====================== YEAR ENDED DECEMBER 31, 2003 35% 54% 11% Year ended December 31, 2002 37% 50% 13% Year ended December 31, 2001 38% 48% 14%
63 Footnotes continued: -------------------- (c) Segment earnings include charges and credits for major infrequently occurring transactions in lieu of U.S. federal income taxes. In 2003, the amounts allocated to the oil and gas segment were charges of $6 million. In 2002, the amounts allocated to the segments were charges of $1 million and a credit of $403 million in oil and gas and chemical, respectively. In 2001, the amounts allocated to the segments were charges of $56 million and a credit of $42 million in oil and gas and chemical, respectively. (d) Includes unallocated net interest expense, administration expense, environmental remediation and other items. 2001 also includes pipeline lease income and pipeline depreciation expense. (e) Includes unallocated income taxes. (f) Oil and gas includes the 2001 gain on sale of interest in Indonesian Tangguh LNG project of $399 million, net of tax. Chemicals includes the 2002 gain on sale of Equistar investment of $164 million, net of tax, and the 2001 writedown of Equistar of $240 million, net of tax. (g) Includes the following significant items affecting earnings for the years ended December 31:
Benefit (Charge) (In millions) 2003 2002 2001 ======================================================= ========== ========== ========== CORPORATE Debt repayment charge $ (61) $ -- $ -- Loss on sale of pipeline-owning entity * -- -- (272) Discontinued operations, net * -- (79) (1) Settlement of state tax issue -- -- 70 Tax effect of pre-tax adjustments 21 -- 148 Changes in accounting principles, net * (68) (95) (24) -------------------------------------------------------- ---------- ---------- ----------
* Amounts shown after-tax. (h) Excludes acquisitions of businesses. Amounts include capitalized interest of $4 million in 2003, $12 million in 2002 and $5 million in 2001. (i) Represents revenue from an electricity co-generation facility in Taft, Louisiana. GEOGRAPHIC AREAS In millions
Net sales (a) Property, plant and equipment, net ---------------------------------- ---------------------------------- For the years ended December 31, 2003 2002 2001 2003 2002 2001 ================================ ======== ======== ======== ======== ======== ======== United States $ 6,805 $ 5,198 $ 6,288 $ 11,602 $ 10,996 $ 11,170 Qatar 691 566 539 1,171 955 859 Colombia 489 381 179 100 98 81 Yemen 472 422 377 349 316 273 Ecuador 220 98 82 224 176 109 Canada 206 150 136 38 33 31 Oman 178 158 151 229 155 122 Pakistan 168 151 113 156 189 49 United Arab Emirates -- -- -- 109 93 1 Other Foreign 97 214 237 27 25 96 -------- -------- -------- -------- -------- -------- Total $ 9,326 $ 7,338 $ 8,102 $ 14,005 $ 13,036 $ 12,791 ================================ ======== ======== ======== ======== ======== ========
(a) Sales are shown by individual country based on the location of the entity making the sale. 64 NOTE 16 COSTS AND RESULTS OF OIL AND GAS PRODUCING ACTIVITIES -------------------------------------------------------------------------------- Capitalized costs relating to oil and gas producing activities and related accumulated depreciation, depletion and amortization, were as follows:
Consolidated Subsidiaries ------------------------------------------------------------------- Other United Latin Middle Eastern Other Total In millions States America East Hemisphere Total Interests(c) Worldwide =============================== ========== ========= ========= ========== ========= ========= ========= DECEMBER 31, 2003 Proved properties $ 10,547 $ 978 $ 3,298 $ 246 $ 15,069 $ 34 $ 15,103 Unproved properties (a) 867 10 20 -- 897 1 898 ---------- --------- --------- ---------- --------- --------- --------- TOTAL PROPERTY COSTS 11,414 988 3,318 246 15,966 35 16,001 Support facilities 443 57 97 81 678 -- 678 ---------- --------- --------- ---------- --------- --------- --------- TOTAL CAPITALIZED COSTS (b) 11,857 1,045 3,415 327 16,644 35 16,679 Accumulated depreciation, depletion and amortization (2,949) (720) (1,557) (171) (5,397) (1) (5,398) ---------- --------- --------- ---------- --------- --------- --------- NET CAPITALIZED COSTS $ 8,908 $ 325 $ 1,858 $ 156 $ 11,247 $ 34 $ 11,281 =============================== ========== ========= ========= ========== ========= ========= ========= DECEMBER 31, 2002 Proved properties $ 9,736 $ 883 $ 2,706 $ 259 $ 13,584 $ 35 $ 13,619 Unproved properties (a) 1,205 2 102 -- 1,309 -- 1,309 ---------- --------- --------- ---------- --------- --------- --------- TOTAL PROPERTY COSTS 10,941 885 2,808 259 14,893 35 14,928 Support facilities 332 50 58 51 491 -- 491 ---------- --------- --------- ---------- --------- --------- --------- TOTAL CAPITALIZED COSTS (b) 11,273 935 2,866 310 15,384 35 15,419 Accumulated depreciation, depletion and amortization (2,560) (661) (1,348) (121) (4,690) 9 (4,681) ---------- --------- --------- ---------- --------- --------- --------- NET CAPITALIZED COSTS $ 8,713 $ 274 $ 1,518 $ 189 $ 10,694 $ 44 $ 10,738 =============================== ========== ========= ========= ========== ========= ========= ========= DECEMBER 31, 2001 Proved properties $ 9,027 $ 789 $ 2,372 $ 142 $ 12,330 $ (2) $ 12,328 Unproved properties (a) 1,606 2 13 -- 1,621 -- 1,621 ---------- --------- --------- ---------- --------- --------- --------- TOTAL PROPERTY COSTS 10,633 791 2,385 142 13,951 (2) 13,949 Support facilities 290 43 49 8 390 19 409 ---------- --------- --------- ---------- --------- --------- --------- TOTAL CAPITALIZED COSTS (b) 10,923 834 2,434 150 14,341 17 14,358 Accumulated depreciation, depletion and amortization (2,210) (622) (1,177) (99) (4,108) 27 (4,081) ---------- --------- --------- ---------- --------- --------- --------- NET CAPITALIZED COSTS $ 8,713 $ 212 $ 1,257 $ 51 $ 10,233 $ 44 $ 10,277 =============================== ========== ========= ========= ========== ========= ========= =========
(a) Primarily consists of California properties. (b) Includes costs related to leases, exploration costs, lease and well equipment, pipelines and terminals, gas plants and other equipment. (c) Includes capitalized costs for equity investees in Russia and Yemen, partially offset by minority interest for a Colombian affiliate. 65 Costs incurred in oil and gas property acquisition, exploration and development activities, whether capitalized or expensed, were as follows:
Consolidated Subsidiaries ---------------------------------------------------------------- Other United Latin Middle Eastern Other Total In millions States America East Hemisphere Total Interests (b) Worldwide (c) =============================== ========== ========= ========= ========== ========= ========= ========= DECEMBER 31, 2003 Acquisition of properties Proved $ 345 $ -- $ 19 $ -- $ 364 $ -- $ 364 Unproved 4 -- -- -- 4 -- 4 Exploration costs 27 30 17 24 98 (1) 97 Development costs 465 (a) 98 516 18 1,097 10 1,107 ---------- --------- --------- ---------- --------- --------- --------- $ 841 $ 128 $ 552 $ 42 $ 1,563 $ 9 $ 1,572 =============================== ========== ========= ========= ========== ========= ========= ========= DECEMBER 31, 2002 Acquisition of properties Proved $ 72 $ -- $ 19 $ 72 $ 163 $ -- $ 163 Unproved -- -- 29 -- 29 -- 29 Exploration costs 54 30 34 16 134 -- 134 Development costs 457 (a) 97 312 24 890 7 897 ---------- --------- --------- ---------- --------- --------- --------- $ 583 $ 127 $ 394 $ 112 $ 1,216 $ 7 $ 1,223 =============================== ========== ========= ========= ========== ========= ========= ========= DECEMBER 31, 2001 Acquisition of properties Proved $ 10 $ -- $ 19 $ -- $ 29 $ -- $ 29 Unproved 43 -- 10 -- 53 -- 53 Exploration costs 57 65 31 23 176 (5) 171 Development costs 602 (a) 58 229 18 907 11 918 ---------- --------- --------- ---------- --------- --------- --------- $ 712 $ 123 $ 289 $ 41 $ 1,165 $ 6 $ 1,171 =============================== ========== ========= ========= ========== ========= ========= =========
(a) Excludes capitalized CO2 of $48 million in 2003, $42 million in 2002 and $48 million in 2001. (b) Includes equity investees' costs in Russia and Yemen, partially offset by minority interest for a Colombian affiliate. (c) Excludes capitalized asset retirement obligation costs of $12 million in 2003. See Note 4 for transition information on capitalized asset retirement obligation costs. 66 The results of operations of Occidental's oil and gas producing activities, which exclude oil and gas trading activities and items such as asset dispositions, corporate overhead, interest and royalties, were as follows:
Consolidated Subsidiaries ------------------------------------------------------------------- Other United Latin Middle Eastern Other Total In millions States America East Hemisphere Total Interests(c) Worldwide =============================== ========== ========= ========= ========== ========= ========= ========= FOR THE YEAR ENDED DECEMBER 31, 2003 Revenues $ 3,637 $ 612 $ 1,341 (a) $ 147 $ 5,737 $ 138 $ 5,875 Production costs 813 122 183 16 1,134 91 1,225 Exploration expenses 79 20 17 23 139 (1) 138 Other operating expenses 207 41 76 13 337 7 344 Depreciation, depletion and amortization 637 60 209 48 954 17 971 ---------- --------- --------- ---------- --------- --------- --------- PRETAX INCOME 1,901 369 856 47 3,173 24 3,197 Income tax expense(b) 500 179 415 (a) 26 1,120 9 1,129 ---------- --------- --------- ---------- --------- --------- --------- RESULTS OF OPERATIONS $ 1,401 $ 190 $ 441 $ 21 $ 2,053 $ 15 $ 2,068 =============================== ========== ========= ========= ========== ========= ========= ========= FOR THE YEAR ENDED DECEMBER 31, 2002 Revenues $ 2,622 $ 453 $ 1,146 (a) $ 133 $ 4,354 $ 107 $ 4,461 Production costs 753 92 137 21 1,003 61 1,064 Exploration expenses 105 27 28 15 175 1 176 Other operating expenses 152 (7) 59 8 212 10 222 Depreciation, depletion and amortization 570 41 171 24 806 13 819 ---------- --------- --------- ---------- --------- --------- --------- PRETAX INCOME 1,042 300 751 65 2,158 22 2,180 Income tax expense(b) 210 113 357 (a) 28 708 10 718 ---------- --------- --------- ---------- --------- --------- --------- RESULTS OF OPERATIONS $ 832 $ 187 $ 394 $ 37 $ 1,450 $ 12 $ 1,462 =============================== ========== ========= ========= ========== ========= ========= ========= FOR THE YEAR ENDED DECEMBER 31, 2001 Revenues $ 3,471 $ 245 $ 1,066 (a) $ 100 $ 4,882 $ 137 $ 5,019 Production costs 773 68 111 12 964 67 1,031 Exploration expenses 42 91 49 12 194 (10) 184 Other operating expenses 141 5 45 20 211 4 215 Depreciation, depletion and amortization 535 27 159 12 733 14 747 ---------- --------- --------- ---------- --------- --------- --------- PRETAX INCOME 1,980 54 702 44 2,780 62 2,842 Income tax expense(b) 530 20 395 (a) 35 980 26 1,006 ---------- --------- --------- ---------- --------- --------- --------- RESULTS OF OPERATIONS $ 1,450 $ 34 $ 307 $ 9 $ 1,800 $ 36 1,836 =============================== ========== ========= ========= ========== ========= ========= =========
(a) Revenues and income tax expense include taxes owed by Occidental but paid by governmental entities on its behalf. (b) U.S. federal income taxes reflect expenses allocated for U.S. income tax purposes only related to oil and gas activities, including allocated interest and corporate overhead. Foreign income taxes were included in geographic areas on the basis of operating results. (c) Includes results of operations for equity investees in Russia and Yemen, partially offset by minority interest for a Colombian affiliate. 67 RESULTS PER UNIT OF PRODUCTION (Unaudited)
Consolidated Subsidiaries ---------------------------------------------------------------- Other United Latin Middle Eastern Other Total States America East Hemisphere Total Interests (b) Worldwide (c) =============================== ========== ========= ========= ========== ========= ========= ========= FOR THE YEAR ENDED DECEMBER 31, 2003 Revenues from net production Oil ($/bbl.) $ 28.74 $ 26.98 $ 39.49 (a) $ 26.68 $ 31.02 $ 16.30 $ 29.91 (a) ========== ========= ========= ========== ========= ========= ========= Natural gas ($/Mcf) $ 4.81 $ -- $ -- $ 2.04 $ 4.49 $ -- $ 4.49 ========== ========= ========= ========== ========= ========= ========= Barrel of oil equivalent ($/bbl.)(b,c) $ 28.57 $ 26.98 $ 39.49 (a) $ 18.52 $ 29.90 $ 16.30 $ 29.14 (a) Production costs 6.39 5.38 5.39 2.02 5.91 8.50 6.08 Exploration expenses 0.62 0.88 0.50 2.90 0.72 -- 0.68 Other operating expenses 1.63 1.81 2.24 1.64 1.76 0.79 1.71 Depreciation, depletion and amortization 5.00 2.64 6.15 6.05 4.97 1.93 4.82 ---------- --------- --------- ---------- --------- --------- --------- PRETAX INCOME 14.93 16.27 25.21 5.91 16.54 5.08 15.85 Income tax expense 3.93 7.89 12.22 (a) 3.27 5.84 2.19 5.60 (a) ---------- --------- --------- ---------- --------- --------- --------- RESULTS OF OPERATIONS $ 11.00 $ 8.38 $ 12.99 $ 2.64 $ 10.70 $ 2.89 $ 10.25 =============================== ========== ========= ========= ========== ========= ========= ========= FOR THE YEAR ENDED DECEMBER 31, 2002 Revenues from net production Oil ($/bbl.) $ 23.47 $ 23.26 $ 34.12 (a) $ 22.63 $ 26.20 $ 14.98 $ 25.37 (a) ========== ========= ========= ========== ========= ========= ========= Natural gas ($/Mcf) $ 2.89 $ -- $ -- $ 2.08 $ 2.81 $ -- $ 2.81 ========== ========= ========= ========== ========= ========= ========= Barrel of oil equivalent ($/bbl.)(b,c) $ 21.30 $ 23.26 $ 34.12 (a) $ 17.76 $ 23.71 $ 14.98 $ 23.24 (a) Production costs 6.12 4.72 4.08 2.80 5.46 6.75 5.54 Exploration expenses 0.85 1.39 0.83 2.00 0.95 0.10 0.92 Other operating expenses 1.23 (0.36) 1.76 1.07 1.15 0.78 1.16 Depreciation, depletion and amortization 4.63 2.11 5.09 3.20 4.39 1.76 4.27 ---------- --------- --------- ---------- --------- --------- --------- PRETAX INCOME 8.47 15.40 22.36 8.69 11.76 5.59 11.35 Income tax expense 1.71 5.80 10.63 (a) 3.74 3.86 2.35 3.74 (a) ---------- --------- --------- ---------- --------- --------- --------- RESULTS OF OPERATIONS $ 6.76 $ 9.60 $ 11.73 $ 4.95 $ 7.90 $ 3.24 $ 7.61 =============================== ========== ========= ========= ========== ========= ========= ========= FOR THE YEAR ENDED DECEMBER 31, 2001 Revenues from net production Oil ($/bbl.) $ 22.82 $ 19.87 $ 33.47 (a) $ 22.63 $ 25.41 $ 15.70 $ 24.65 (a) ========== ========= ========= ========== ========= ========= ========= Natural gas ($/Mcf) $ 6.40 $ -- $ -- $ 2.29 $ 6.11 $ -- $ 6.11 ========== ========= ========= ========== ========= ========= ========= Barrel of oil equivalent ($/bbl.)(b,c) $ 28.34 $ 19.87 $ 33.47 (a) $ 17.99 $ 28.35 $ 15.70 $ 27.69 (a) Production costs 6.31 5.51 3.49 2.16 5.60 7.20 5.70 Exploration expenses 0.34 7.38 1.54 2.16 1.13 -- 1.02 Other operating expenses 1.15 0.41 1.41 3.60 1.23 0.50 1.19 Depreciation, depletion and amortization 4.37 2.19 4.99 2.16 4.26 1.70 4.12 ---------- --------- --------- ---------- --------- --------- --------- PRETAX INCOME 16.17 4.38 22.04 7.91 16.13 6.30 15.66 Income tax expense 4.33 1.62 12.40 (a) 6.29 5.69 2.80 5.55 (a) ---------- --------- --------- ---------- --------- --------- --------- RESULTS OF OPERATIONS $ 11.84 $ 2.76 $ 9.64 $ 1.62 $ 10.44 $ 3.50 $ 10.11 =============================== ========== ========= ========= ========== ========= ========= =========
(a) Revenues and income tax expense include taxes owed by Occidental but paid by governmental entities on its behalf. (b) Natural gas volumes have been converted to equivalent barrels based on energy content of six Mcf of gas to one barrel of oil. (c) Revenues from net production exclude royalty payments and other adjustments. (d) Includes results of operations for equity investees in Russia and Yemen. (e) The computation of results per unit of production included in the denominator 2.1 mmboe, 4.2 mmboe and 7.8 mmboe produced by Occidental that were subject to volumetric production payments for the years 2003, 2002 and 2001, respectively. 68
2003 QUARTERLY FINANCIAL DATA (Unaudited) Occidental Petroleum Corporation In millions, except per-share amounts and Subsidiaries Three months ended MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31 ============================================================= ============ ============ ============ ============ Segment net sales Oil and gas $ 1,553 $ 1,440 $ 1,480 $ 1,530 Chemical 790 785 793 810 Other 28 41 46 30 ------------ ------------ ------------ ------------ Net sales $ 2,371 $ 2,266 $ 2,319 $ 2,370 ============ ============ ============ ============ Gross profit $ 1,073 $ 1,001 $ 1,038 $ 1,087 ============ ============ ============ ============ Segment earnings Oil and gas $ 727 $ 637 $ 660 $ 640 Chemical 35 43 61 71 ------------ ------------ ------------ ------------ 762 680 721 711 Unallocated corporate items Interest expense, net (124) (53) (59) (53) Income taxes (178) (167) (160) (157) Trust preferred distributions and other (11) (11) (12) (10) Other (56) (75) (44) (109) ------------ ------------ ------------ ------------ Income from continuing operations 393 374 446 382 Discontinued operations, net -- -- -- -- Cumulative effect of changes in accounting principles, net (68) -- -- -- ------------ ------------ ------------ ------------ Net income $ 325 $ 374 $ 446 $ 382 ============ ============ ============ ============ Basic earnings per common share Income from continuing operations $ 1.04 $ .98 $ 1.16 $ .99 Discontinued operations, net -- -- -- -- Cumulative effect of changes in accounting principles, net (.18) -- -- -- ------------ ------------ ------------ ------------ Basic earnings per common share $ .86 $ .98 $ 1.16 $ .99 ============ ============ ============ ============ Diluted earnings per common share Income from continuing operations $ 1.03 $ .97 $ 1.14 $ .97 Discontinued operations, net -- -- -- -- Cumulative effect of changes in accounting principles, net (.18) -- -- -- ------------ ------------ ------------ ------------ Diluted earnings per common share $ .85 $ .97 $ 1.14 $ .97 ============ ============ ============ ============ Dividends per common share $ .26 $ .26 $ .26 $ .26 ============ ============ ============ ============ Market price per common share High $ 30.74 $ 34.40 $ 35.84 $ 42.98 Low $ 27.17 $ 29.55 $ 30.64 $ 34.70 ============================================================= ============ ============ ============ ============
69
2002 QUARTERLY FINANCIAL DATA (Unaudited) Occidental Petroleum Corporation In millions, except per-share amounts and Subsidiaries Three months ended MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31 ============================================================= ============ ============ ============ ============ Segment net sales Oil and gas $ 958 $ 1,165 $ 1,224 $ 1,287 Chemical 565 702 739 698 ------------ ------------ ------------ ------------ Net sales $ 1,523 $ 1,867 $ 1,963 $ 1,985 ============ ============ ============ ============ Gross profit $ 536 $ 742 $ 838 $ 856 ============ ============ ============ ============ Segment earnings(loss) Oil and gas $ 306 $ 421 $ 490 $ 490 Chemical (31) 34 214 58 ------------ ------------ ------------ ------------ 275 455 704 548 Unallocated corporate items Interest expense, net (56) (66) (73) (58) Income taxes (44) (101) (105) (114) Trust preferred distributions and other (11) (12) (12) (12) Other (41) (35) (38) (41) ------------ ------------ ------------ ------------ Income from continuing operations 123 241 476 323 Discontinued operations, net (3) (1) (74) (1) Cumulative effect of changes in accounting principles, net (95) -- -- -- ------------ ------------ ------------ ------------ Net income $ 25 $ 240 $ 402 $ 322 ============ ============ ============ ============ Basic earnings per common share Income from continuing operations $ .33 $ .64 $ 1.26 $ .85 Discontinued operations, net (.01) -- (.19) -- Cumulative effect of changes in accounting principles, net (.25) -- -- -- ------------ ------------ ------------ ------------ Basic earnings per common share $ .07 $ .64 $ 1.07 $ .85 ============ ============ ============ ============ Diluted earnings per common share Income from continuing operations $ .33 $ .63 $ 1.25 $ .84 Discontinued operations, net (.01) -- (.19) -- Cumulative effect of changes in accounting principles, net (.25) -- -- -- ------------ ------------ ------------ ------------ Diluted earnings per common share $ .07 $ .63 $ 1.06 $ .84 ============ ============ ============ ============ Dividends per common share $ .25 $ .25 $ .25 $ .25 ============ ============ ============ ============ Market price per common share High $ 29.19 $ 30.75 $ 30.08 $ 30.74 Low $ 24.29 $ 28.05 $ 22.98 $ 26.47 ============================================================= ============ ============ ============ ============
70 SUPPLEMENTAL OIL AND GAS INFORMATION (Unaudited) The following tables set forth Occidental's net interests in quantities of proved developed and undeveloped reserves of crude oil, condensate and natural gas and changes in such quantities. Crude oil reserves (in millions of barrels) include condensate. The reserves are stated after applicable royalties. These estimates include reserves in which Occidental holds an economic interest under production-sharing contracts and other economic arrangements. The reserve estimation process involves reservoir engineers, geoscientists, planning engineers and financial analysts. As part of this process, all reserve volumes are estimated by a forecast of production rates, operating costs and capital expenditures. Price differentials between benchmark prices and prices realized and specifics of each operating agreement are then used to estimate the net reserves. Production rate forecasts are derived by a number of methods, including estimates from decline curve analyses, material balance calculations that take into account the volume of substances replacing the volumes produced and associated reservoir pressure changes, or computer simulation of the reservoir performance. Operating costs and capital costs are forecast based on past experience combined with expectations of future cost for the specific reservoirs. In many cases, activity-based cost models for a reservoir are utilized to project operating costs as production rates and the number of wells for production and injection vary. A team consisting of the Chief Engineer of Worldwide Reservoir Characterization, the Chief Petrophysicist, the Manager of Production Geoscience, a Manager of Financial Planning and Analysis and the Worldwide Reserves Coordinator perform a review of the reserve estimates at the location where the estimates were developed. Estimates of proven reserves are collected in a database and changes in this database are reviewed by engineering personnel to ensure accuracy. Finally, reserve volumes and changes are reviewed and approved by Occidental's senior management. OIL RESERVES In millions of barrels
Consolidated Subsidiaries ------------------------------------------------------------------- Other United Latin Middle Eastern Other Total In millions States America East (b) Hemisphere Total Interests(a) Worldwide ================================= ========== ========= ========= ========== ========= ========= ========= PROVED DEVELOPED AND UNDEVELOPED RESERVES BALANCE AT DECEMBER 31, 2000 1,346 144 258 10 1,758 45 1,803 Revisions of previous estimates (14) 10 24 1 21 8 29 Improved recovery 92 -- 47 -- 139 -- 139 Extensions and discoveries 22 10 24 -- 56 -- 56 Purchases of proved reserves 3 -- -- -- 3 -- 3 Sales of proved reserves -- -- -- -- -- -- -- Production (78) (12) (32) (2) (124) (9) (133) --------------------------------- ---------- --------- --------- ---------- --------- --------- --------- BALANCE AT DECEMBER 31, 2001 1,371 152 321 9 1,853 44 1,897 Revisions of previous estimates 28 13 (31) 3 13 (1) 12 Improved recovery 69 1 42 -- 112 5 117 Extensions and discoveries 22 11 6 1 40 -- 40 Purchases of proved reserves 51 -- -- 5 56 2 58 Sales of proved reserves (4) -- -- -- (4) -- (4) Production (85) (19) (34) (4) (142) (8) (150) --------------------------------- ---------- --------- --------- ---------- --------- --------- --------- BALANCE AT DECEMBER 31, 2002 1,452 158 304 14 1,928 42 1,970 Revisions of previous estimates (11) -- 10 -- (1) 6 5 Improved recovery 58 6 21 -- 85 4 89 Extensions and discoveries 4 11 25 1 41 6 47 Purchases of proved reserves 98 -- -- -- 98 -- 98 Sales of proved reserves (8) -- -- -- (8) -- (8) Production (93) (23) (34) (3) (153) (10) (163) --------------------------------- ---------- --------- --------- ---------- --------- --------- --------- BALANCE AT DECEMBER 31, 2003 1,500 152 326 12 1,990 48 2,038 ================================= ========== ========= ========= ========== ========= ========= ========= PROVED DEVELOPED RESERVES December 31, 2000 1,079 90 197 8 1,374 36 1,410 ========== ========= ========= ========== ========= ========= ========= December 31, 2001 1,106 91 232 8 1,437 35 1,472 ========== ========= ========= ========== ========= ========= ========= December 31, 2002 1,183 85 228 12 1,508 34 1,542 ========== ========= ========= ========== ========= ========= ========= DECEMBER 31, 2003 1,262 116 227 11 1,616 35 1,651 ================================= ========== ========= ========= ========== ========= ========= =========
(a) Includes reserves applicable to equity investees in Russia and Yemen, partially offset by minority interests for a Colombian affiliate. (b) All Middle East reserves are related to production-sharing contracts. 71 GAS RESERVES In billions of cubic feet
Consolidated Subsidiaries ------------------------------------------------------------------- Other United Latin Middle Eastern Other Total In millions States America East (b) Hemisphere Total Interests Worldwide ================================= ========== ========= ========= ========== ========= ========= ========= PROVED DEVELOPED AND UNDEVELOPED RESERVES BALANCE AT DECEMBER 31, 2000 2,094 -- -- 116 2,210 -- 2,210 Revisions of previous estimates (53) -- -- 4 (49) -- (49) Improved recovery 23 -- -- -- 23 -- 23 Extensions and discoveries 118 -- -- 4 122 -- 122 Purchases of proved reserves 4 -- -- -- 4 -- 4 Sales of proved reserves (1) -- -- -- (1) -- (1) Production (a) (223) -- -- (18) (241) -- (241) --------------------------------- ---------- --------- --------- ---------- --------- --------- --------- BALANCE AT DECEMBER 31, 2001 1,962 -- -- 106 2,068 -- 2,068 Revisions of previous estimates (39) -- -- (15) (54) -- (54) Improved recovery 39 -- 106 6 151 -- 151 Extensions and discoveries 57 -- -- 3 60 -- 60 Purchases of proved reserves 14 -- -- 45 59 -- 59 Sales of proved reserves (6) -- -- -- (6) -- (6) Production (a) (206) -- -- (23) (229) -- (229) --------------------------------- ---------- --------- --------- ---------- --------- --------- --------- BALANCE AT DECEMBER 31, 2002 1,821 -- 106 122 2,049 -- 2,049 Revisions of previous estimates 47 -- (10) 7 44 -- 44 Improved recovery 68 -- -- 2 70 9 79 Extensions and discoveries 38 -- 558 1 597 -- 597 Purchases of proved reserves 55 -- -- -- 55 -- 55 Sales of proved reserves (9) -- -- -- (9) -- (9) Production (a) (194) -- -- (27) (221) -- (221) --------------------------------- ---------- --------- --------- ---------- --------- --------- --------- BALANCE AT DECEMBER 31, 2003 1,826 -- 654 105 2,585 9 2,594 ================================= ========== ========= ========= ========== ========= ========= ========= PROVED DEVELOPED RESERVES December 31, 2000 1,814 -- -- 84 1,898 -- 1,898 ========== ========= ========= ========== ========= ========= ========= December 31, 2001 1,718 -- -- 89 1,807 -- 1,807 ========== ========= ========= ========== ========= ========= ========= December 31, 2002 1,630 -- -- 110 1,740 -- 1,740 ========== ========= ========= ========== ========= ========= ========= DECEMBER 31, 2003 1,618 -- 91 94 1,803 9 1,812 ================================= ========== ========= ========= ========== ========= ========= =========
(a) Production excludes 12.7 bcf, 25.3 bcf and 28.0 bcf subject to volumetric production payments for the years 2003, 2002 and 2001, respectively. (b) All Middle East reserves are related to production-sharing contracts. 72 STANDARDIZED MEASURE, INCLUDING YEAR-TO-YEAR CHANGES THEREIN, OF DISCOUNTED FUTURE NET CASH FLOWS For purposes of the following disclosures, estimates were made of quantities of proved reserves and the periods during which they are expected to be produced. Future cash flows were computed by applying year-end prices to Occidental's share of estimated annual future production from proved oil and gas reserves, net of royalties. Future development and production costs were computed by applying year-end costs to be incurred in producing and further developing the proved reserves. Future income tax expenses were computed by applying, generally, year-end statutory tax rates (adjusted for permanent differences, tax credits, allowances and foreign income repatriation considerations) to the estimated net future pre-tax cash flows. The discount was computed by application of a 10 percent discount factor. The calculations assumed the continuation of existing economic, operating and contractual conditions at each of December 31, 2003, 2002 and 2001. However, such arbitrary assumptions have not necessarily proven to be the case in the past. Other assumptions of equal validity would give rise to substantially different results. The year-end prices used to calculate future cash flows vary by producing area and market conditions. For the 2003, 2002 and 2001 disclosures, the West Texas Intermediate oil prices used were $32.52/bbl, $31.17/bbl and $19.84/bbl, respectively. The Henry Hub gas prices used for the 2003, 2002 and 2001 disclosures were $5.79/MMBtu, $4.75/MMBtu and $2.57/MMBtu, respectively. STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS In millions
Consolidated Subsidiaries ------------------------------------------------------------------- Other United Latin Middle Eastern Other States America East Hemisphere Total Interests(a) =========================================== ========== ========= ========= ========== ========= ========= AT DECEMBER 31, 2003 Future cash flows $ 53,939 $ 3,977 $ 10,232 $ 556 $ 68,704 $ 987 Future costs Production costs and other operating expenses (22,584) (1,404) (2,945) (112) (27,045) (434) Development costs (b) (1,931) (129) (1,382) (39) (3,481) (87) ---------- --------- --------- ---------- --------- --------- FUTURE NET CASH FLOWS BEFORE INCOME TAXES 29,424 2,444 5,905 405 38,178 466 Future income tax expense (9,090) (1,070) (626) (169) (10,955) (141) ---------- --------- --------- ---------- --------- --------- FUTURE NET CASH FLOWS 20,334 1,374 5,279 236 27,223 325 Ten percent discount factor (11,644) (355) (2,390) (47) (14,436) (81) ---------- --------- --------- ---------- --------- --------- STANDARDIZED MEASURE $ 8,690 $ 1,019 $ 2,889 $ 189 $ 12,787 $ 244 =========================================== ========== ========= ========= ========== ========= ========= AT DECEMBER 31, 2002 Future cash flows $ 46,806 $ 3,407 $ 8,555 $ 628 $ 59,396 $ 429 Future costs Production costs and other operating expenses (18,288) (907) (2,227) (102) (21,524) (286) Development costs (b) (1,997) (165) (969) (28) (3,159) (40) ---------- --------- --------- ---------- --------- --------- FUTURE NET CASH FLOWS BEFORE INCOME TAXES 26,521 2,335 5,359 498 34,713 103 Future income tax expense (7,929) (906) (333) (190) (9,358) -- ---------- --------- --------- ---------- --------- --------- FUTURE NET CASH FLOWS 18,592 1,429 5,026 308 25,355 103 Ten percent discount factor (10,342) (440) (2,079) (65) (12,926) (22) ---------- --------- --------- ---------- --------- --------- STANDARDIZED MEASURE $ 8,250 $ 989 $ 2,947 $ 243 $ 12,429 $ 81 =========================================== ========== ========= ========= ========== ========= ========= AT DECEMBER 31, 2001 Future cash flows $ 28,146 $ 2,259 $ 5,670 $ 340 $ 36,415 $ 469 Future costs Production costs and other operating expenses (14,404) (868) (1,813) (69) (17,154) (321) Development costs (b) (2,282) (204) (556) (19) (3,061) (32) ---------- --------- --------- ---------- --------- --------- FUTURE NET CASH FLOWS BEFORE INCOME TAXES 11,460 1,187 3,301 252 16,200 116 Future income tax expense (2,224) (483) (306) (90) (3,103) (26) ---------- --------- --------- ---------- --------- --------- FUTURE NET CASH FLOWS 9,236 704 2,995 162 13,097 90 Ten percent discount factor (5,088) (199) (1,238) (38) (6,563) (22) ---------- --------- --------- ---------- --------- --------- STANDARDIZED MEASURE $ 4,148 $ 505 $ 1,757 $ 124 $ 6,534 $ 68 =========================================== ========== ========= ========= ========== ========= =========
(a) Includes future net cash flows applicable to equity investees in Russia and Yemen, partially offset by minority interests for a Colombian affiliate. (b) Includes dismantlement and abandonment costs. 73 CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM PROVED RESERVE QUANTITIES In millions
For the years ended December 31, 2003 2002 2001 ==================================================================================================== ======== ======== ======== BEGINNING OF YEAR $ 12,429 $ 6,534 $ 15,180 -------- -------- -------- Sales and transfers of oil and gas produced, net of production costs and other operating expenses (4,162) (2,910) (3,383) Net change in prices received per barrel, net of production costs and other operating expenses 1,874 9,684 (12,737) Extensions, discoveries and improved recovery, net of future production and development costs 1,287 1,496 1,238 Change in estimated future development costs (833) (543) (931) Revisions of quantity estimates 133 (87) 58 Development costs incurred during the period 1,078 954 902 Accretion of discount 1,545 757 1,895 Net change in income taxes (638) (2,820) 4,138 Purchases and sales of reserves in place, net 637 448 19 Changes in production rates and other (563) (1,084) 155 -------- -------- -------- NET CHANGE 358 5,895 (8,646) -------- -------- -------- END OF YEAR $ 12,787 $ 12,429 $ 6,534 ==================================================================================================== ======== ======== ========
AVERAGE SALES PRICES AND AVERAGE PRODUCTION COSTS OF OIL AND GAS The following table sets forth, for each of the three years in the period ended December 31, 2003, Occidental's approximate average sales prices and average production costs of oil and gas. Production costs are the costs incurred in lifting the oil and gas to the surface and include gathering, treating, primary processing, field storage, property taxes and insurance on proved properties, but do not include depreciation, depletion and amortization, royalties, income taxes, interest, general and administrative and other expenses.
Consolidated Subsidiaries ------------------------------------------------------- Other United Latin Middle Eastern Other Total States America(a) East Hemisphere(a) Total Interests(c) Worldwide ================================================== ======= ======= ======= ========== ======= ========= ========= 2003 Oil -- Average sales price ($/bbl.) $ 28.74 $ 27.21 $ 27.81(d) $ 26.61 $ 28.18 $ 15.95 $ 27.25 Gas -- Average sales price ($/Mcf) $ 4.81 $ -- $ -- $ 2.04 $ 4.45 $ -- $ 4.45 Average oil and gas production cost ($/bbl.) (b) $ 6.39 $ 5.38 $ 5.39 $ 2.02 $ 5.91 $ 8.50 $ 6.08 -------------------------------------------------- ------- ------- ------- ---------- ------- --------- --------- 2002 Oil -- Average sales price ($/bbl.) $ 23.47 $ 23.14 $ 24.13(d) $ 23.02 $ 23.56 $ 14.80 $ 22.91 Gas -- Average sales price ($/Mcf) $ 2.89 $ -- $ -- $ 2.08 $ 2.81 $ -- $ 2.81 Average oil and gas production cost ($/bbl.) (b) $ 6.12 $ 4.72 $ 4.08 $ 2.80 $ 5.46 $ 6.75 $ 5.54 -------------------------------------------------- ------- ------- ------- ---------- ------- --------- --------- 2001 Oil -- Average sales price ($/bbl.) $ 21.74 $ 20.10 $ 23.00(d) $ 22.64 $ 21.91 $ 15.57 $ 21.41 Gas -- Average sales price ($/Mcf) $ 6.40 $ -- $ -- $ 2.29 $ 6.09 $ -- $ 6.09 Average oil and gas production cost ($/bbl.) (b) $ 6.31 $ 5.51 $ 3.49 $ 2.16 $ 5.60 $ 7.20 $ 5.70 -------------------------------------------------- ------- ------- ------- ---------- ------- --------- ---------
(a) Sales prices include royalties with respect to certain of Occidental's interests. (b) Natural gas volumes have been converted to equivalent barrels based on energy content of six Mcf of gas to one barrel of oil. (c) Includes prices and costs applicable to equity investees in Russia and Yemen. (d) Excludes implied taxes. 74 NET PRODUCTIVE AND DRY -- EXPLORATORY AND DEVELOPMENT WELLS COMPLETED The following table sets forth, for each of the three years in the period ended December 31, 2003, Occidental's net productive and dry-exploratory and development wells completed.
Consolidated Subsidiaries ------------------------------------------------------------------ Other United Latin Middle Eastern Other Total States America East Hemisphere Total Interests(a) Worldwide ================================= ========= ========= ========= ========== ========= ========= ========= 2003 Oil -- Exploratory 1.0 2.2 1.3 0.4 4.9 (0.1) 4.8 Development 277.2 26.2 61.0 2.1 366.5 4.0 370.5 Gas -- Exploratory -- -- -- -- -- -- -- Development 35.1 -- 1.3 -- 36.4 -- 36.4 Dry -- Exploratory 4.0 6.0 3.6 1.3 14.9 (0.9) 14.0 Development 15.7 1.2 1.7 -- 18.6 0.1 18.7 --------------------------------- --------- --------- --------- ---------- --------- --------- ---------- 2002 Oil -- Exploratory 2.9 1.2 3.8 -- 7.9 -- 7.9 Development 258.5 16.8 58.1 2.7 336.1 8.6 344.7 Gas -- Exploratory -- -- -- 0.5 0.5 -- 0.5 Development 17.9 -- -- 0.6 18.5 -- 18.5 Dry -- Exploratory 5.1 1.2 1.6 0.5 8.4 -- 8.4 Development 20.8 1.1 -- 0.8 22.7 (0.1) 22.6 --------------------------------- --------- --------- --------- ---------- --------- --------- ---------- 2001 Oil -- Exploratory 3.0 -- 2.6 0.5 6.1 -- 6.1 Development 432.1 15.1 45.6 2.3 495.1 11.4 506.5 Gas -- Exploratory 7.8 -- -- -- 7.8 -- 7.8 Development 38.1 -- -- 0.5 38.6 -- 38.6 Dry -- Exploratory 10.1 1.2 0.7 1.1 13.1 (0.3) 12.8 Development 34.7 -- -- 0.3 35.0 -- 35.0 --------------------------------- --------- --------- --------- ---------- --------- --------- ----------
(a) Includes amounts applicable to equity investees in Russia and Yemen, partially offset by minority interests in a Colombian affiliate. PRODUCTIVE OIL AND GAS WELLS The following table sets forth, as of December 31, 2003, Occidental's productive oil and gas wells (both producing wells and wells capable of production). The numbers in parentheses indicate the number of wells with multiple completions.
Consolidated Subsidiaries ------------------------------------------------------------------- Other United Latin Middle Eastern Other Total Wells at December 31, 2003 States America East Hemisphere Total Interests (c) Worldwide ========================== =========== =========== =========== =========== =========== =========== =========== Oil -- Gross (a) 17,346 (403) 321 (--) 678 (21) 72 (--) 18,417 (424) 425 (62) 18,842 (486) Net (b) 11,743 (291) 169 (--) 380 (21) 32 (--) 12,342 (312) 197 (33) 12,539 (345) Gas -- Gross (a) 2,441 (60) -- (--) 6 (1) 35 (--) 2,482 (61) 2 (--) 2,484 (61) Net (b) 2,046 (40) -- (--) 5 (1) 15 (--) 2,066 (41) 1 (--) 2,067 (41) -------------------------- ----------- ----------- ----------- ----------- ----------- ----------- -----------
(a) The total number of wells in which interests are owned. (b) The sum of fractional interests. (c) Includes amounts applicable to equity investees in Russia and Yemen, partially offset by minority interests in a Colombian affiliate. 75 PARTICIPATION IN EXPLORATORY AND DEVELOPMENT WELLS BEING DRILLED The following table sets forth, as of December 31, 2003, Occidental's participation in exploratory and development wells being drilled.
Consolidated Subsidiaries -------------------------------------------------------------- Other United Latin Middle Eastern Other Total Wells at December 31, 2003 States America East Hemisphere Total Interests(a) Worldwide ================================= ========== ========== ========== ========== ========== ========== ========== Exploratory and development wells -- Gross 30 4 6 3 43 5 48 -- Net 20 3 4 1 28 2 30 --------------------------------- ---------- ---------- ---------- ---------- ---------- ---------- ----------
(a) Includes amounts applicable to equity investees in Russia and Yemen, partially offset by minority interests in a Colombian affiliate. At December 31, 2003, Occidental was participating in 101 pressure maintenance projects in the United States, 5 in Latin America, 43 in the Middle East and 5 in the Other Eastern Hemisphere. OIL AND GAS ACREAGE The following table sets forth, as of December 31, 2003, Occidental's holdings of developed and undeveloped oil and gas acreage.
Consolidated Subsidiaries -------------------------------------------------------------- Other Thousands of acres at United Latin Middle Eastern Other Total December 31, 2003 States America East Hemisphere Total Interests(e) Worldwide ============================== ========== ========== ========== ========== ========== ========== ========== Developed (a) -- Gross (b) 4,248 39 520 554 5,361 16 5,377 -- Net (c) 2,853 23 210 264 3,350 35 3,385 Undeveloped (d) -- Gross (b) 1,932 3,929 16,346 12,606 34,813 6 34,819 -- Net (c) 1,181 2,440 6,973 5,918 16,512 (195) 16,317 ------------------------------ ---------- ---------- ---------- ---------- ---------- ---------- ----------
(a) Acres spaced or assigned to productive wells. (b) Total acres in which interests are held. (c) Sum of the fractional interests owned based on working interests, or interests under production-sharing contracts and other economic arrangements. (d) Acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas, regardless of whether the acreage contains proved reserves. (e) Includes amounts applicable to equity investees in Russia and Yemen, partially offset by minority interests in a Colombian affiliate. 76 OIL AND NATURAL GAS PRODUCTION PER DAY The following table sets forth, for each of the three years in the period ended December 31, 2003, Occidental's oil, NGL and natural gas production per day.
2003 2002 2001 =========================================================================== ========== ========== ========== United States Crude oil and liquids (MBL) California 81 86 76 Permian 150 142 137 Horn Mountain 21 1 -- Hugoton 4 3 -- ---------- ---------- ---------- TOTAL 256 232 213 Natural Gas (MMCF) California 252 286 303 Hugoton 138 148 159 Permian 129 130 148 Horn Mountain 13 -- -- ---------- ---------- ---------- TOTAL 532 564 610 Latin America Crude oil (MBL) Colombia 37 40 21 Ecuador 25 13 13 ---------- ---------- ---------- TOTAL 62 53 34 Middle East Crude oil (MBL) Oman 12 13 12 Qatar 45 42 43 Yemen 35 37 33 ---------- ---------- ---------- TOTAL 92 92 88 Other Eastern Hemisphere Crude oil (MBL) Pakistan 9 10 7 Natural Gas (MMCF) Pakistan 74 63 50 Barrels of Oil Equivalent (MBOE) -------------------------------- Subtotal consolidated subsidiaries 520 492 452 Colombia - minority interest (5) (5) (3) Russia - Occidental net interest 30 27 27 Yemen - Occidental net interest 2 1 -- ---------- ---------- ---------- Total worldwide production 547 515 476 =========================================================================== ========== ========== ==========
77
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS Occidental Petroleum Corporation In millions and Subsidiaries Additions ----------------------- Balance at Charged to Charged to Balance at Beginning Costs and Other End of of Period Expenses Accounts Deductions Period ========================================================= ========== ========== ========== ========== ========== 2003 Allowance for doubtful accounts $ 28 $ -- $ -- $ (4) $ 24 ========== ========== ========== ========== ========== Environmental $ 393 $ 64 $ -- $ (85)(a) $ 372 Foreign and other taxes, litigation and other reserves 1,104 14 80 (31) 1,167 ---------- ---------- ---------- ---------- ---------- $ 1,497 $ 78 $ 80 $ (116) $ 1,539 (b) ========================================================= ========== ========== ========== ========== ========== 2002 Allowance for doubtful accounts $ 35 $ -- $ -- $ (7) $ 28 ========== ========== ========== ========== ========== Environmental $ 454 $ 25 $ -- $ (86)(a) $ 393 Foreign and other taxes, litigation and other reserves 930 8 193 (27) 1,104 ---------- ---------- ---------- ---------- ---------- $ 1,384 $ 33 $ 193 $ (113) $ 1,497 (b) ========================================================= ========== ========== ========== ========== ========== 2001 Allowance for doubtful accounts $ 25 $ 12 $ -- $ (2) $ 35 ========== ========== ========== ========== ========== Environmental $ 402 $ 111 $ 16 $ (75)(a) $ 454 Foreign and other taxes, litigation and other reserves 1,001 10 27 (108)(c) 930 ---------- ---------- ---------- ---------- ---------- $ 1,403 $ 121 $ 43 $ (183) $ 1,384 (b) ========================================================= ========== ========== ========== ========== ==========
(a) Primarily represents payments. (b) Of these amounts, $132 million, $160 million and $165 million in 2003, 2002 and 2001, respectively, are classified as current. (c) Included a reclassification of $46 million to the "Deferred and other domestic and foreign income taxes" account. 78 ITEM 9 CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE Not applicable. ITEM 9A CONTROLS AND PROCEDURES Occidental's Chief Executive Officer and Chief Financial Officer supervised and participated in Occidental's evaluation of its disclosure controls and procedures as of the end of the period covered by this report. Disclosure controls and procedures are controls and procedures designed to ensure that information required to be disclosed in Occidental's periodic reports filed or submitted under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission's rules and forms. Based upon that evaluation, Occidental's Chief Executive Officer and Chief Financial Officer concluded that Occidental's disclosure controls and procedures are effective. There has been no change in Occidental's internal control over financial reporting during the fourth quarter of 2003 that has materially affected, or is reasonably likely to materially affect, Occidental's internal control over financial reporting. PART III ITEM 10 DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT Occidental has adopted a Code of Business Conduct (Code). The Code applies to the chief executive officer, chief financial officer, chief accounting officer and persons performing similar functions (Key Personnel). The Code also applies to the company's directors, its employees and the employees of entities it controls. The Code is posted on the Occidental website www.oxy.com and a copy is available to stockholders upon request. Occidental will satisfy any disclosure requirement under Item 10 of Form 8-K regarding an amendment to, or waiver from, any provision of the Code with respect to its Key Personnel or directors by disclosing the nature of that amendment or waiver on its website. This item incorporates by reference the information regarding Occidental's directors appearing under the caption "Election of Directors" in Occidental's definitive proxy statement filed in connection with its April 30, 2004, Annual Meeting of Stockholders (2004 Proxy Statement). See also the list of Occidental's executive officers and related information under "Executive Officers of the Registrant" in Part I of this report. ITEM 11 EXECUTIVE COMPENSATION This item incorporates by reference the information appearing under the captions "Executive Compensation" (excluding, however, the information appearing under the subcaptions "Report of the Executive Compensation and Human Resources Committee" and "Performance Graph") and "Election of Directors -- Information Regarding the Board of Directors and Its Committees" in the 2004 Proxy Statement. ITEM 12 SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT This item incorporates by reference the information with respect to security ownership appearing under the caption "Security Ownership of Certain Beneficial Owners and Management" in the 2004 Proxy Statement. ITEM 13 CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS Not applicable. ITEM 14 PRINCIPAL ACCOUNTANT FEES AND SERVICES This item incorporates by reference the information with respect to accountant fees and services appearing under the sub-captions "Audit and Other Fees" and "Report of the Audit Committee" in the 2004 Proxy Statement. PART IV ITEM 15 EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K (a) (1) AND (2). FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULE Reference is made to the Index to Financial Statements and Related Information under Item 8 in Part II hereof, where these documents are listed. (a) (3). EXHIBITS 3.(i)* Restated Certificate of Incorporation of Occidental, dated November 12, 1999 (filed as Exhibit 3.(i) to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 1999, File No. 1-9210). 3.(i)(a)* Certificate of Change of Location of Registered Office and of Registered Agent, dated July 6, 2001. (filed as Exhibit 3.1(i) to the Registration Statement on Form S-3 of Occidental, File No. 333-82246). ----------------------------------- * Incorporated herein by reference 79 3.(ii) Bylaws of Occidental, as amended through February 12, 2004. 4.1* Occidental Petroleum Corporation Five-Year Credit Agreement, dated as of January 4, 2001 among Occidental, Chase Securities Inc. and Banc of America Securities, LLC, as Co-Lead Arrangers, The Chase Manhattan Bank, as Syndication Agent, Bank of America, N.A. and ABN Amro Bank N.V., as Co-Documentation Agents, and The Bank of Nova Scotia, as Administrative Agent (filed as Exhibit 4.1 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2000, File No. 1-9210). 4.2* Indenture (Senior Debt Securities), dated as of April 1, 1998, between Occidental and The Bank of New York, as Trustee (filed as Exhibit 4 to the Registration Statement on Form S-3 of Occidental, File No. 333-52053). 4.3* Specimen certificate for shares of Common Stock (filed as Exhibit 4.9 to the Registration Statement on Form S-3 of Occidental, File No. 333-82246). 4.4 Instruments defining the rights of holders of other long-term debt of Occidental and its subsidiaries are not being filed since the total amount of securities authorized under each of such instruments does not exceed 10 percent of the total assets of Occidental and its subsidiaries on a consolidated basis. Occidental agrees to furnish a copy of any such instrument to the Commission upon request. All of the Exhibits numbered 10.1 to 10.51 are management contracts and compensatory plans required to be identified specifically as responsive to Item 601(b)(10)(iii)(A) of Regulation S-K pursuant to Item 15(c) of Form 10-K. 10.1* Employment Agreement, dated as of November 17, 2000, between Occidental and Dr. Ray R. Irani (filed as Exhibit 10.2 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2000, File No. 1-9210). 10.2* Employment Agreement, dated as of November 17, 2000, between Occidental and Dr. Dale R. Laurance (filed as Exhibit 10.3 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2000, File No. 1-9210). 10.3* Employment Agreement, dated as of November 17, 2000, between Occidental and Stephen I. Chazen (filed as Exhibit 10.4 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2000, File No. 1-9210). 10.4* Employment Agreement, dated May 19, 2003, between Occidental and Donald P. de Brier (filed as Exhibit 10.1 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended June 30, 2003, File No. 1-9210). 10.5* Form of Indemnification Agreement between Occidental and each of its directors and certain executive officers (filed as Exhibit B to the Proxy Statement of Occidental for its May 21, 1987, Annual Meeting of Stockholders, File No. 1-9210). 10.6* Occidental Petroleum Corporation Split Dollar Life Insurance Program and Related Documents (filed as Exhibit 10.2 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended September 30, 1994, File No. 1-9210). 10.7* Split Dollar Life Insurance Agreement, dated January 24, 2002, by and between Occidental and Donald P. de Brier (filed as Exhibit 10.1 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended March 31, 2002, File No. 1-9210). 10.8* Occidental Petroleum Insured Medical Plan, as amended and restated effective April 29, 1994, amending and restating the Occidental Petroleum Corporation Executive Medical Plan (as amended and restated effective April 1, 1993) (filed as Exhibit 10 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ending March 31, 1994, File No. 1-9210). 10.9* Occidental Petroleum Corporation 1987 Stock Option Plan, as amended through September 12, 2002 (filed as Exhibit 10.1 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended September 30, 2002, File No. 1-9210). 10.10* Form of Nonqualified Stock Option Agreement under Occidental Petroleum Corporation 1987 Stock Option Plan (filed as Exhibit 10.2 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended March 31, 1992, File No. 1-9210). 10.11* Form of Nonqualified Stock Option Agreement, with Stock Appreciation Right, under Occidental Petroleum Corporation 1987 Stock Option Plan (filed as Exhibit 10.3 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended March 31, 1992, File No. 1-9210). ----------------------------------- * Incorporated herein by reference 80 10.12* Form of Incentive Stock Option Agreement under Occidental Petroleum Corporation 1987 Stock Option Plan (filed as Exhibit 10.4 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended March 31, 1992, File No. 1-9210). 10.13* Form of Incentive Stock Option Agreement, with Stock Appreciation Right, under Occidental Petroleum Corporation 1987 Stock Option Plan (filed as Exhibit 10.5 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended March 31, 1992, File No. 1-9210). 10.14 Occidental Petroleum Corporation Deferred Compensation Plan, Second Amendment and Restatement Effective as of January 1, 2003. 10.15* Occidental Petroleum Corporation Senior Executive Supplemental Life Insurance Plan (effective as of January 1, 1986, as amended and restated effective as of January 1, 1996) (filed as Exhibit 10.25 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 1995, File No. 1-9210). 10.16* Occidental Petroleum Corporation Senior Executive Survivor Benefit Plan (effective as of January 1, 1986, as amended and restated effective as of January 1, 1996) (filed as Exhibit 10.27 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 1995, File No. 1-9210). 10.17* Amendment No. 1 to Occidental Petroleum Corporation Senior Executive Survivor Benefit Plan, dated February 28, 2002 (filed as Exhibit 10.2 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended March 31, 2002, File No. 1-9210). 10.18* Occidental Petroleum Corporation 1995 Incentive Stock Plan, as amended (filed as Exhibit 10.28 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 1999, File No. 1-9210). 10.19* Form of Incentive Stock Option Agreement under Occidental Petroleum Corporation 1995 Incentive Stock Plan (filed as Exhibit 99.2 to the Registration Statement on Form S-8 of Occidental, File No. 33-64719). 10.20* Form of Nonqualified Stock Option Agreement under Occidental Petroleum Corporation 1995 Incentive Stock Plan (filed as Exhibit 99.3 to the Registration Statement on Form S-8 of Occidental, File No. 33-64719). 10.21* Form of Restricted Stock Agreement under Occidental Petroleum Corporation 1995 Incentive Stock Plan (filed as Exhibit 99.5 to the Registration Statement on Form S-8 of Occidental, File No. 33-64719). 10.22* Form of Performance Stock Agreement under Occidental Petroleum Corporation 1995 Incentive Stock Plan (filed as Exhibit 99.6 to the Registration Statement on Form S-8 of Occidental, File No. 33-64719). 10.23* Form of Incentive Stock Option Agreement under Occidental Petroleum Corporation 1995 Incentive Stock Plan (filed as Exhibit 10.2 to the Current Report on Form 8-K of Occidental, dated January 6, 1999 (date of earliest event reported), filed January 6, 1999, File No. 1-9210, amends Form previously filed as Exhibit 10.1 to the Registration Statement on Form S-8 of Occidental, File No. 33-64719 and incorporated by reference as Exhibit 10.39 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 1997, File No. 1-9210). 10.24* Form of Nonqualified Stock Option Agreement under Occidental Petroleum Corporation 1995 Incentive Stock Plan (filed as Exhibit 10.3 to the Current Report on Form 8-K of Occidental, dated January 6, 1999 (date of earliest event reported), filed January 6, 1999, File No. 1-9210, amends Form previously filed as Exhibit 10.2 to the Registration Statement on Form S-8 of Occidental, File No. 33-64719 and incorporated by reference as Exhibit 10.40 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 1997, File No. 1-9210). 10.25* Form of Incentive Stock Option Agreement (With Accelerated Performance Vesting) under Occidental Petroleum Corporation 1995 Incentive Stock Plan (filed as Exhibit 10.2 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended June 30, 1999, File No. 1-9210). 10.26* Form of Nonqualified Stock Option Agreement (With Accelerated Performance Vesting) under Occidental Petroleum Corporation 1995 Incentive Stock Plan (filed as Exhibit 10.3 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended June 30, 1999, File No. 1-9210). 10.27* Form of 1997 Performance Stock Option Agreement under the 1995 Incentive Stock Plan of Occidental Petroleum Corporation (filed as Exhibit 10.2 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended June 30, 1997, File No. 1-9210). ----------------------------------- * Incorporated herein by reference 81 10.28* Form of Amendment to 1997 Performance Stock Option Agreement under the 1995 Incentive Stock Plan of Occidental Petroleum Corporation (filed as Exhibit 10.43 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 1999, File No. 1-9210). 10.29* Occidental Petroleum Corporation 1996 Restricted Stock Plan for Non-Employee Directors (as amended effective April 25, 2003) (filed as Exhibit 10.1 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended March 31, 2003, File No. 1-9210). 10.30* Form of Restricted Stock Option Assignment under Occidental Petroleum Corporation 1996 Restricted Stock Plan for Non-Employee Directors (filed as Exhibit 99.2 to the Registration Statement on Form S-8 of Occidental, File No. 333-02901). 10.31* Form of Restricted Stock Agreement under Occidental Petroleum Corporation 1996 Restricted Stock Plan for Non-Employee Directors (filed as Exhibit 10.3 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended March 31, 2003, File No. 1-9210). 10.32* Occidental Petroleum Corporation Supplemental Retirement Plan, Amended and Restated Effective as of January 1, 1999, reflecting amendments effective through March 1, 2001 (filed as Exhibit 10.3 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended March 31, 2001, File No. 1-9210). 10.33* Occidental Petroleum Corporation 2001 Incentive Compensation Plan (as amended through September 12, 2002) (filed as Exhibit 10.2 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended September 30, 2002, File No. 1-9210). 10.34* Form of Incentive Stock Option Agreement under Occidental Petroleum Corporation 2001 Incentive Compensation Plan (filed as Exhibit 10.1 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended September 30, 2001, File No. 1-9210). 10.35* Form of Nonqualified Stock Option Agreement under Occidental Petroleum Corporation 2001 Incentive Compensation Plan (filed as Exhibit 10.2 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended September 30, 2001, File No. 1-9210). 10.36* Form of Restricted Common Share Agreement under Occidental Petroleum Corporation 2001 Incentive Compensation Plan (filed as Exhibit 10.40 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2001, File No. 1-9210). 10.37* Form of Performance Based Stock Agreement under Occidental Petroleum Corporation 2001 Incentive Compensation Plan (filed as Exhibit 10.41 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2001, File No. 1-9210). 10.38* Form of Incentive Stock Option Agreement under Occidental Petroleum Corporation 2001 Incentive Compensation Plan (July 2002 version) (filed as Exhibit 10.4 to the Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2002, File No. 1-9210). 10.39* Form of Nonqualified Stock Option Agreement under Occidental Petroleum Corporation 2001 Incentive Compensation Plan (July 2002 version) (filed as Exhibit 10.5 to the Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2002, File No. 1-9210). 10.40* Form of Restricted Common Share Agreement (with mandatory deferred issuance of shares) under Occidental Petroleum Corporation 2001 Incentive Compensation Plan (filed as Exhibit 10.6 to the Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2002, File No. 1-9210). 10.41* Form of Restricted Common Share Agreement (with mandatory deferred issuance of shares) under Occidental Petroleum Corporation 2001 Incentive Compensation Plan (December 2002 version) (filed as Exhibit 10.47 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2002, File No. 1-9210). 10.42* Terms and Conditions for Incentive Stock Option Award under Occidental Petroleum Corporation 2001 Incentive Compensation Plan (July 2003 version) (filed as Exhibit 10.3 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended June 30, 2003, File No. 1-9210). 10.43* Terms and Conditions for Nonqualified Stock Option Award under Occidental Petroleum Corporation 2001 Incentive Compensation Plan (July 2003 version) (filed as Exhibit 10.4 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended June 30, 2003, File No. 1-9210). ----------------------------------- * Incorporated herein by reference 82 10.44* Terms and Conditions of Restricted Share Unit Award (with mandatory deferred issuance of shares) under Occidental Petroleum Corporation 2001 Incentive Compensation Plan (July 2003 version) (filed as Exhibit 10.5 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended June 30, 2003, File No. 1-9210). 10.45 Terms and Conditions of Restricted Share Unit Award (with mandatory deferred issuance of shares) under Occidental Petroleum Corporation 2001 Incentive Compensation Plan (December 2003 version). 10.46 Terms and Conditions of Performance Based Stock Award (deferred issuance of shares) under Occidental Petroleum Corporation 2001 Incentive Compensation Plan (December 2003 version - Corporate) 10.47 Terms and Conditions of Performance Based Stock Award (deferred issuance of shares) under Occidental Petroleum Corporation 2001 Incentive Compensation Plan (December 2003 version - Occidental Chemical). 10.48* Occidental Petroleum Corporation Deferred Stock Program (filed as Exhibit 10.3 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended September 30, 2002, File No. 1-9210). 10.49* Occidental Petroleum Corporation Executive Incentive Compensation Plan (filed as Exhibit 10.2 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended March 31, 2001, File No. 1-9210). 10.50 Description of financial counseling program. 10.51 Description of group excess liability insurance program. 10.52* Securities Purchase Agreement, dated as of July 8, 2002, by and between Lyondell Chemical Company and Occidental Chemical Holding Corporation (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Occidental dated August 22, 2002 (date of earliest event reported), filed September 6, 2002, File No. 1-9210). 10.53* Stockholders Agreement, dated as of August 22, 2002, by and among Lyondell Chemical Company and the Stockholders as defined therein (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K of Occidental dated August 22, 2002 (date of earliest event reported), filed September 6, 2002, File No. 1-9210). 10.54* Warrant for the Purchase of Shares of Common Stock, issued August 22, 2002 (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K of Occidental dated August 22, 2002 (date of earliest event reported), filed September 6, 2002, File No. 1-9210). 10.55* Registration Rights Agreement, dated as of August 22, 2002, by and between Occidental Chemical Holding Corporation and Lyondell Chemical Company (incorporated by reference to Exhibit 10.4 to the Current Report on Form 8-K of Occidental dated August 22, 2002 (date of earliest event reported), filed September 6, 2002, File No. 1-9210). 10.56* Occidental Partner Sub Purchase Agreement, dated July 8, 2002, by and among Lyondell Chemical Company, Occidental Chemical Holding Corporation, Oxy CH Corporation and Occidental Chemical Corporation (incorporated by reference to Exhibit 10.5 to the Current Report on Form 8-K of Occidental dated August 22, 2002 (date of earliest event reported), filed September 6, 2002, File No. 1-9210). 12 Statement regarding computation of total enterprise ratios of earnings to fixed charges for the five years ended December 31, 2003. 21 List of subsidiaries of Occidental at December 31, 2003. 23 Independent Auditors' Consent. 31.1 Certification of CEO Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 31.2 Certification of CFO Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 32.1 Certifications of CEO and CFO Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. ----------------------------------- * Incorporated herein by reference 83 (b) REPORTS ON FORM 8-K During the fourth quarter of 2003, Occidental filed the following Current Reports on Form 8-K: 1. Current Report on Form 8-K dated October 21, 2003 (date of earliest event reported), filed on October 21, 2003, for the purpose of reporting, under Items 9 and 12, Occidental's results of operations for the third quarter ended September 30, 2003, and speeches and supplemental investor information relating to Occidental's third quarter 2003 earnings announcement (which information under Items 9 and 12 shall not be deemed to be filed). 2. Current Report on Form 8-K dated November 18, 2003 (date of earliest event reported), filed on November 18, 2003, for the purpose of reporting, under Item 9, a presentation by Dr. Ray R. Irani, Chief Executive Officer (which information under Item 9 shall not be deemed to be filed). During the first quarter of 2004, Occidental filed the following Current Reports on Form 8-K: 1. Current Report on Form 8-K dated January 22, 2004 (date of earliest event reported), filed on January 22, 2004, for the purpose of reporting, under Items 9 and 12, Occidental's results of operations for the fourth quarter ended December 31, 2003, and speeches and supplemental investor information relating to Occidental's fourth quarter 2003 earnings announcement (which information under Items 9 and 12 shall not be deemed to be filed). 2. Current Report on Form 8-K dated February 5, 2004 (date of earliest event reported), filed on February 5, 2004, for the purpose of reporting, under Item 9, a presentation by Dr. Dale R. Laurance, President (which information under Item 9 shall not be deemed to be filed). 84 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. OCCIDENTAL PETROLEUM CORPORATION March 1, 2004 By: /s/ RAY R. IRANI -------------------------------------- Ray R. Irani Chairman of the Board of Directors and Chief Executive Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
SIGNATURE TITLE DATE --------- ----- ---- /s/ RAY R. IRANI Chairman of the Board of March 1, 2004 ------------------------------- Directors and Chief Ray R. Irani Executive Officer /s/ STEPHEN I. CHAZEN Executive Vice President - March 1, 2004 ------------------------------- Corporate Development Stephen I. Chazen and Chief Financial Officer /s/ SAMUEL P. DOMINICK, JR. Vice President and March 1, 2004 ------------------------------- Controller (Chief Samuel P. Dominick, Jr. Accounting Officer) /s/ RONALD W. BURKLE Director March 1, 2004 ------------------------------- Ronald W. Burkle /s/ JOHN S. CHALSTY Director March 1, 2004 ------------------------------- John S. Chalsty /s/ EDWARD P. DJEREJIAN Director March 1, 2004 ------------------------------- Edward P. Djerejian /s/ R. CHAD DREIER Director March 1, 2004 ------------------------------- R. Chad Dreier /s/ JOHN E. FEICK Director March 1, 2004 ------------------------------- John E. Feick /s/ DALE R. LAURANCE Director March 1, 2004 ------------------------------- Dale R. Laurance
85
SIGNATURE TITLE DATE --------- ----- ---- /s/ IRVIN W. MALONEY Director March 1, 2004 ------------------------------- Irvin W. Maloney /s/ RODOLFO SEGOVIA Director March 1, 2004 ------------------------------- Rodolfo Segovia /s/ AZIZ D. SYRIANI Director March 1, 2004 ------------------------------- Aziz D. Syriani /s/ ROSEMARY TOMICH Director March 1, 2004 ------------------------------- Rosemary Tomich /s/ WALTER L. WEISMAN Director March 1, 2004 ------------------------------- Walter L. Weisman
86 This page intentionally left blank. 87 EXHIBIT INDEX EXHIBITS -------- 3.(ii) Bylaws of Occidental, as amended through February 12, 2004. 10.14 Occidental Petroleum Corporation Deferred Compensation Plan, Second Amendment and Restatement Effective as of January 1, 2003. 10.45 Terms and Conditions of Restricted Share Unit Award (with mandatory deferred issuance of shares) under Occidental Petroleum Corporation 2001 Incentive Compensation Plan (December 2003 version). 10.46 Terms and Conditions of Performance Based Stock Award (deferred issuance of shares) under Occidental Petroleum Corporation 2001 Incentive Compensation Plan (December 2003 version - Corporate). 10.47 Terms and Conditions of Performance Based Stock Award (deferred issuance of shares) under Occidental Petroleum Corporation 2001 Incentive Compensation Plan (December 2003 version - Occidental Chemical). 10.50 Description of financial counseling program. 10.51 Description of group excess liability insurance program. 12 Statement regarding the computation of total enterprise ratios of earnings to fixed charges for the five years ended December 31, 2003. 21 List of subsidiaries of Occidental at December 31, 2003. 23 Independent Auditors' Consent. 31.1 Certification of CEO Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 31.2 Certification of CFO Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 32.1 Certifications of CEO and CFO Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002