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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
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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