Edgar Filing: OCCIDENTAL PETROLEUM CORP /DE/

Occidental Petroleum Corporation

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form 10-K

þ Annual Report Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934
For the fiscal year ended December 31, 2006

o Transition Report Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934
For the transition period from to

Commission File Number 1-9210

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
Common Stock	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. þ YES o NO

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. (Note: Checking the box will not relieve any registrant required to file reports pursuant to Section 13 or 15(d) of the Exchange Act from their obligations under those Sections). o YES
þ NO

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. þ YES
o 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. þ

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer or a non-accelerated filer. (See definition of "accelerated filer" and "large accelerated filer" in Rule 12b-2 of the Exchange Act).
þ Large Accelerated Filer o Accelerated Filer
o Non-Accelerated Filer

Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2). o YES þ NO

The aggregate market value of the voting stock held by nonaffiliates of the registrant was approximately $42.6 billion, computed by reference to the closing price on the New York Stock Exchange composite tape of $51.28 per share of Common Stock on June 30, 2006. 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 potential affiliate status is not a conclusive determination for other purposes.

At January 31, 2007, there were approximately 838,100,111 shares of Common Stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s definitive Proxy Statement, filed in connection with its May 4, 2007, 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	4
	Employees	4
	Environmental Regulation	5
	Available Information	5
Item 1A	Risk Factors	5
Item 1B	Unresolved Staff Comments	6
Item 3	Legal Proceedings	6
Item 4	Submission of Matters to a Vote of Security Holders	6
	Executive Officers	6
Part II
Item 5	Market for Registrant’s Common Equity, Related Stockholder Matters and Purchases of Equity Securities	7
Item 6	Selected Financial Data	9
Item 7	Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) (Incorporating Item 7A)	9
	Strategy	9
	Oil and Gas Segment	11
	Chemical Segment	16
	Corporate and Other	17
	Segment Results of Operations	17
	Significant Items Affecting Earnings	19
	Taxes	20
	Consolidated Results of Operations	20
	Consolidated Analysis of Financial Position	21
	Liquidity and Capital Resources	22
	Off-Balance-Sheet Arrangements	24
	Lawsuits, Claims, Commitments, Contingencies and Related Matters	25
	Environmental Liabilities and Expenditures	26
	Foreign Investments	27
	Critical Accounting Policies and Estimates	27
	Significant Accounting Changes	30
	Derivative Activities and Market Risk	31
	Safe Harbor Discussion Regarding Outlook and Other Forward-Looking Data	33
Item 8	Financial Statements and Supplementary Data	34
	Management's Annual Assessment of and Report on Internal Control Over Financial Reporting	34
	Report of Independent Registered Public Accounting Firm on Consolidated Financial Statements	35
	Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting	36
	Consolidated Statements of Income	37
	Consolidated Balance Sheets	38
	Consolidated Statements of Stockholders’ Equity	40
	Consolidated Statements of Comprehensive Income	40
	Consolidated Statements of Cash Flows	41
	Notes to Consolidated Financial Statements	42
	Quarterly Financial Data (Unaudited)	78
	Supplemental Oil and Gas Information (Unaudited)	80
	Financial Statement Schedule:
	Schedule II – Valuation and Qualifying Accounts	88
Item 9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	89
Item 9A	Controls and Procedures	89
	Disclosure Controls and Procedures	89
Part III
Item 10	Directors, Executive Officers and Corporate Governance	89
Item 11	Executive Compensation	89
Item 12	Security Ownership of Certain Beneficial Owners and Management	89
Item 13	Certain Relationships and Related Transactions and Director Independence	89
Item 14	Principal Accountant Fees and Services	89
Part IV
Item 15	Exhibits and Financial Statement Schedules	90

Part I
ITEMS 1 AND 2 BUSINESS AND PROPERTIES

In this report, "Occidental" refers to Occidental Petroleum Corporation, a Delaware corporation (OPC), and/or one or more entities in which it owns a majority voting interest (subsidiaries). Occidental conducts its operations through various oil and gas, chemical and other subsidiaries and affiliates. 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 operated by OPC's subsidiaries. The subsidiaries and other affiliates in the oil and gas segment explore for, develop, produce and market crude oil and natural gas. The subsidiaries and other affiliates in the chemical segment (OxyChem) manufacture and market basic chemicals, vinyls and performance chemicals. For financial information by segment and by geographic area, 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 principally located at the Permian Basin in west Texas and New Mexico, Elk Hills and other locations in California, the Hugoton field in Kansas and Oklahoma, the Gulf of Mexico and western Colorado. International operations are located in Argentina, Bolivia, Colombia, Libya, Oman, Pakistan, Qatar, Russia (sold in January 2007), the United Arab Emirates (UAE) 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 caption "Oil and Gas Segment" in the MD&A section of this report.

Proved Reserves, Production and Properties

The table below shows Occidental’s total oil and natural gas proved reserves and production in 2006, 2005 and 2004. See the MD&A section of this report, Note 18 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 proved reserves, the estimation process and production by country. On May 12, 2006, Occidental reported to the United States Department of Energy on Form EIA-28 proved oil and gas reserves at December 31, 2005. The amounts reported were the same as the amounts reported in Occidental’s 2005 Annual Report.

Comparative Oil and Gas Proved Reserves and Production
Oil in millions of barrels; natural gas in billions of cubic feet; BOE in millions of barrels of oil equivalent

	2006					2005					2004
RESERVES	Oil	^(a)	Gas	BOE	^(b)	Oil	^(a)	Gas	BOE	^(b)	Oil	^(a)	Gas	BOE	^(b)
United States	1,678		2,442	2,085		1,636		2,338	2,026		1,494		2,101	1,844
International	556		1,368	784		350		1,140	540		395		874	541
Consolidated Subsidiaries ^(c)	2,234		3,810	2,869	^(d)	1,986		3,478	2,566	^(d)	1,889		2,975	2,385	^(d)
Other Interests ^(e)	30		—	30		45		—	45		43		—	43
PRODUCTION
United States	98		217	134		92		202	126		93		186	124
International	68		51	77		50		44	57		49		47	57
Consolidated Subsidiaries ^(c)	166		268	211		142		246	183		142		233	181
Other Interests ^(e)	7		8	8		7		6	8		9		—	9

(a)	Includes natural gas liquids and condensate.
(b)	Natural gas volumes have been converted to BOE 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)	Occidental has classified its Ecuador block 15 operations as discontinued operations on a retrospective application basis and excluded them from this table.
(d)	Stated on a net basis and after applicable royalties. Includes reserves related to production-sharing contracts (PSCs) and other economic arrangements. Proved reserves from PSCs in the Middle East/North Africa and from other economic arrangements in the United States were 486 million barrels of oil equivalent (MMBOE) and 119 MMBOE in 2006, 472 MMBOE and 104 MMBOE in 2005 and 450 MMBOE and 90 MMBOE in 2004, respectively.
(e)	Includes Occidental's share of reserves and production from equity investees in Russia (sold in January 2007) and Yemen, partially offset by minority interests for a Colombian affiliate.

Competition and Sales and Marketing

As a producer of crude oil and natural gas, Occidental competes with numerous other domestic and foreign private and government producers. Crude oil and natural gas are commodities that are sensitive to prevailing global and, in certain cases, local 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 rights 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/North Africa and Latin America.

CHEMICAL OPERATIONS
General

OxyChem manufactures and markets basic chemicals, vinyls and performance chemicals. For additional information regarding Occidental’s chemical segment, see the information under the caption “Chemical Segment” in the MD&A section of this report.

Products and Properties

OxyChem owns and operates chemical manufacturing plants at 23 sites in the United States and 3 sites internationally. OxyChem permanently shut down its mercaptans facility in Baytown, Texas in the fourth quarter of 2006 and its polyvinyl chloride (PVC) facility in Alberta, Canada in the first quarter of 2006. OxyChem produces the following chemical products:

Principal Products	Major Uses	Annual Capacity ^(a)		Location
*Basic Chemicals*
Chlorine	Chlorovinyl chain and water treatment	–	3.7 million tons ^(b)	–	Alabama, Kansas, Louisiana, New York and Texas
Chlorine	Chlorovinyl chain and water treatment	–	0.3 million tons ^(c)	–	Brazil and Chile
Caustic Soda	Pulp, paper and aluminum production	–	3.9 million tons ^(b)	–	Kansas, Louisiana, New York, and Texas
Caustic Soda	Pulp, paper and aluminum production	–	0.4 million tons ^(c)	–	Brazil and Chile
Chlorinated organics	Silicones, paint stripping, pharmaceuticals and refrigerants	–	0.9 billion pounds	–	Louisiana and Kansas
Potassium chemicals	Glass, fertilizers, cleaning products and rubber	–	0.3 million tons	–	Alabama
Ethylene dichloride (EDC)	Raw material for vinyl chloride monomer (VCM)	–	2.1 billion pounds	–	Louisiana
Ethylene dichloride (EDC)	Raw material for vinyl chloride monomer (VCM)	–	0.3 billion pounds ^(c)	–	Brazil
*Vinyls*
VCM	Precursor for PVC	–	6.2 billion pounds ^(b)	–	Texas
PVC	Piping, insulation, flooring, medical and automotive products and packaging	–	3.7 billion pounds ^(b)	–	Kentucky, New Jersey and Texas
PVC		–	0.6 billion pounds	–	Canada
*Performance Chemicals*
Chlorinated isocyanurates	Swimming pool sanitation and disinfecting products	–	131 million pounds	–	Illinois and Louisiana
Resorcinol	Tire manufacture, wood adhesives and flame retardant synergist	–	50 million pounds	–	Pennsylvania
Sodium silicates	Soaps, detergents and paint pigments	–	0.7 million tons	–	Georgia, Ohio, Illinois, New Jersey, Texas and Alabama

(a)	Estimated at December 31, 2006.
(b)	Includes gross capacity of the OxyVinyls partnership, owned 76 percent by Occidental.
(c)	Includes gross capacity of a joint venture in Brazil, owned 50 percent by Occidental.

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 8,886 people at December 31, 2006, 6,711 of whom were located in the United States. Occidental employed 4,429 people in oil and gas operations and 3,160 people in chemical operations. An additional 1,297 people were employed in administrative and headquarters functions. Approximately 900 United States-based employees and 250 foreign-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 web site at www.oxy.com:

Ø	Forms 10-K, 10-Q, 8-K and amendments to these forms as soon as reasonably practicable after they are filed electronically with the Securities and Exchange Commission (SEC);
Ø	Other SEC filings, including Forms 3, 4 and 5; and
Ø	Corporate governance information, including its corporate governance guidelines, board-committee charters and Code of Business Conduct. (See Part III Item 10 of this report for further information.)

ITEM 1A RISK FACTORS

Volatile global commodity pricing strongly affects Occidental’s results of operations.

Occidental’s financial results typically correlate closely to the volatile prices it obtains for its commodities. Drilling and exploration activity levels, inventory levels, production disruptions, the actions of OPEC (influencing prices or limiting Occidental's production), competing fuel prices, price speculation, changes in consumption patterns, weather and geophysical and technical limitations affect the supply of oil and gas and contribute to price volatility.

Demand, and consequently, the price obtained, for Occidental’s chemical products correlate strongly to the health of the global economy, as well as industry expansion cycles. Occidental also depends on feedstocks and energy to produce chemicals, both of which are commodities subject to significant price fluctuations.

Occidental’s oil and gas business operates in highly competitive environments, which affects, among other things, its profitability and its ability to grow production and replace reserves.

Occidental’s future oil and gas production and its results of operations depend, in part, on its ability to profitably acquire, develop or find additional reserves. Over the past several years Occidental increasingly has replaced reserves through acquisitions. Occidental has many competitors, some of which are larger and better funded, may be willing to accept greater risks or have special competencies. Industry competition for reserves may influence Occidental to:

Ø	shift toward higher risk exploration activity;
Ø	pay more for reinvestment opportunities;
Ø	purchase lesser quality properties; or
Ø	delay expected reserve replacement efforts.

In addition, rising exploration and development activity in the industry generally increases the competition for and costs of, and delays access to, services needed to increase production.

Governmental actions and political instability may affect Occidental’s results of operations.

Occidental’s domestic and foreign oil and gas business is subject to the decisions of many governments and political interests. As a result, Occidental faces risks of:

Ø	changes in laws and regulations, including those related to taxes, royalty rates, permitted production rates, import, export and use of products, environmental protection and climate change, all of which may increase costs;
Ø	expropriation or reduction of entitlements to produce hydrocarbons; and
Ø	refusal to extend exploration, production or development contracts.

Occidental may experience adverse consequences, such as risk of loss or production limitations, because certain of its foreign operations are located in countries occasionally affected by political instability, armed conflict, terrorism, insurgency, civil unrest, security problems, restrictions on production equipment imports and sanctions that prevent continued operations. Exposure to such risks may increase as a greater percentage of Occidental’s future oil and gas production comes from foreign sources.

Occidental’s businesses may experience uninsured catastrophic events.

The occurrence of natural disasters, such as earthquakes, hurricanes and floods, in locations where Occidental operates and events such as well blowouts, oilfield fires, and industrial accidents may affect Occidental’s businesses. Third-party insurance may not provide adequate coverage or Occidental may be self-insured with respect to the related losses.

Occidental’s reserves are based on professional judgments and may be subject to revision.

Calculations of reserves depend on estimates concerning reservoir characteristics and recoverability, as well as oil and gas prices, capital costs and operating costs. If Occidental were required to make unanticipated significant negative reserve revisions, its prospects and stock price may be adversely affected.

Occidental may incur significant losses in exploration or cost overruns in development efforts.

Occidental may misinterpret geologic or engineering data, encounter unexpected geologic conditions or find reserves of disappointing quality or quantity, which may result in significant losses on exploration or development efforts. Occidental bears the risks of project delays and cost overruns due to escalating costs for materials and labor, equipment failures, approval delays, construction delays, border disputes and other associated risks.

Occidental faces risks associated with its mergers, acquisitions and divestitures.

Occidental’s merger, acquisition and divestiture activities carry risks that it may: not fully realize anticipated benefits due to delays, miscalculation of reserves or production or changed circumstances; bear unexpected integration costs or experience other integration difficulties; experience share price declines based on the market’s evaluation of the activity; assume or retain liabilities that are greater than anticipated; or be unable to resell acquired assets as planned or at planned prices.

Information related to competition, foreign operations, litigation, environmental matters, derivatives and market risks, and oil and gas reserve estimation fluctuations appears under the headings: Business and Properties — Oil & Gas Operations — Competition and Sales and Marketing;" MD&A — "Oil & Gas Segment — Business Review ," and "— Industry Outlook" and "Chemical Segment — Business Review," and " — Industry Outlook," "Lawsuits, Claims, Commitments, Contingencies and Related Matters," "Environmental Liabilities and Expenditures," "Foreign Investments” and "Critical Accounting Policies and Estimates," and "Derivative Activities and Market Risk."

ITEM 1B UNRESOLVED STAFF COMMENTS

None.

ITEM 3 LEGAL PROCEEDINGS

For information regarding legal proceedings, see the information in Note 9 to the Consolidated Financial Statements, which is incorporated herein by reference.

An OPC subsidiary is engaged in discussions with the Texas Commission on Environmental Quality (TCEQ) to voluntarily resolve alleged environmental law violations. The alleged violations include exceeding emissions limitations, and failing to meet operating, reporting and recordkeeping requirements relating to a natural gas processing plant in west Texas acquired by the subsidiary in 2005. The TCEQ seeks an administrative penalty of approximately $200,000 although the subsidiary expects to resolve the allegations for less.

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 2006.

EXECUTIVE OFFICERS

The current term of employment of each executive officer of Occidental will expire at the May 4, 2007 organizational meeting of the Board of Directors or when a successor is selected. The following table sets forth the executive officers and significant employees of Occidental:

Name	Age at February 27, 2007	Positions with Occidental and Subsidiaries and Five-Year Employment History
Dr. Ray R. Irani	72	Chairman and Chief Executive Officer since 1990; President since 2005; Director since 1984; Member of Executive Committee and Dividend Committee.
Stephen I. Chazen	60	Senior Executive Vice President since 2004; Chief Financial Officer since 1999; 1994-2004, Executive Vice President — Corporate Development.
Donald P. de Brier	66	Executive Vice President, General Counsel and Secretary since 1993.
Richard W. Hallock	62	Executive Vice President — Human Resources since 1994.
James M. Lienert	54	Executive Vice President — Finance and Planning since 2006; 2004-2006, Vice President; Occidental Chemical Corporation: 2004-2006, President; 2000-2002, Senior Vice President — Basic Chemicals; OxyVinyls: 2002-2004, Senior Vice President.
John W. Morgan	53	Executive Vice President since 2001; 1998-2001, Executive Vice President — Operations; Occidental Oil and Gas Corporation (OOGC): President — Western Hemisphere since 2005; 2004, President; 2001-2004, Executive Vice President — Worldwide Production.
R. Casey Olson	53	Executive Vice President since 2005; 2001-2005, Vice President; OOGC: President - Eastern Hemisphere since 2005; Occidental Development Company: 2004, President; Occidental Middle East Development Company: 2001-2003, President.
James R. Havert	65	Vice President and Treasurer since 1998.
Jim A. Leonard	57	Vice President and Controller since 2005; 2000-2005, Senior Assistant Controller; OOGC: 2000-2005, Senior Vice President — Finance.
B. Chuck Anderson	47	Occidental Chemical Corporation: President since 2006; 2004-2006, Executive Vice President — Chlorovinyls; 2002-2004, Senior Vice President — Basic Chemicals; 2000-2002, President — OxyVinyls.

Part II
ITEM 5 MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND PURCHASES OF EQUITY SECURITIES

TRADING PRICE RANGE AND DIVIDENDS

This section incorporates by reference the quarterly financial data appearing under the caption "Quarterly Financial Data (Unaudited)" after the Notes to the Consolidated Financial Statements 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 41,949 stockholders of record at December 31, 2006, with an estimated 306,994 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. The quarterly financial data, which are included in this report after the Notes to the Consolidated Financial Statements, 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 May 2006, Occidental amended its Restated Certificate of Incorporation to increase the number of authorized shares of common stock to 1.1 billion. The par value per share remained unchanged.

On August 1, 2006, Occidental effected a two-for-one stock split in the form of a stock dividend to shareholders of record as of that date with distribution of the shares on August 15, 2006. The total number of authorized shares of common stock authorized for issuance and associated par value per share were unchanged by this action. All share and per-share amounts have been adjusted to reflect this stock split.

In 2006, the quarterly dividends declared for the common stock were $0.18 per share for the first two quarters of 2006 and $0.22 for the last two quarters of 2006 ($0.80 for the year). On February 15, 2007, a quarterly dividend of $0.22 per share ($0.88 on an annualized basis) was declared on the common stock, payable on April 15, 2007 to stockholders of record on March 9, 2007. 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, 2006, pursuant to outstanding options, rights or warrants granted under Occidental’s equity compensation plans:

(a)	Number of securities to be issued upon exercise of outstanding options, warrants and rights		(b)	Weighted-average exercise price of outstanding options, warrants and rights		(c)	Number of securities remaining available for future issuance under equity compensation plans (excluding securities in column (a))
12,852,466			$32.45			31,327,693 *

* Includes, with respect to:
(a)	the 1995 Incentive Stock Plan, 571,438 shares reserved for issuance pursuant to deferred stock unit awards;
(b)	the 2001 Incentive Compensation Plan, 2,406,382 shares at maximum payout level (1,203,191 at target level) reserved for issuance pursuant to outstanding performance stock awards, 758,410 shares reserved for issuance pursuant to restricted stock unit awards, 2,226,172 shares reserved for issuance pursuant to deferred stock unit awards and 1,842 shares reserved for issuance as dividend equivalents on deferred stock unit awards; and
(c)	the 2005 Long-Term Incentive Plan, 396,640 shares at maximum payout level (198,320 at target level) reserved for issuance pursuant to outstanding performance stock awards, 2,392,114 shares reserved for issuance pursuant to restricted stock unit awards, 1,516,000 shares at maximum payout level (758,000 at target level) reserved for issuance pursuant to outstanding performance-based restricted share units and 367,736 shares reserved for issuance pursuant to deferred stock unit awards.
Of the 21,894,150 shares that are not reserved for issuance under the 2005 Long-Term Incentive Plan, approximately 14.5 million shares are available after giving effect to the provision of the plan that each award, other than options and stock appreciation rights, must be counted against the number of shares available for issuance as three shares for every one share covered by award. Subject to the share count requirement, not more than the approximate 14.5 million shares may be issued or reserved for issuance for options, rights and warrants as well as performance stock awards, restricted stock awards, performance restricted stock awards, stock bonuses and dividend equivalents.

SHARE REPURCHASE ACTIVITIES

Occidental’s share repurchase activities for the year ended December 31, 2006, were as follows:

Period

Total
Number
of Shares
Purchased

Average
Price
Paid
per Share

Total Number of Shares
Purchased as Part of
Publicly Announced
Plans or Programs ^(b)

Maximum Number of
Shares that May Yet be
Purchased Under the
Plans or Programs

First Quarter 2006

4,823,880

^(a)

$ 45.89

4,410,800

Second Quarter 2006

15,252,546

^(a)

$ 49.05

15,080,600

Third Quarter 2006

6,629,901

^(a)

$ 47.98

6,118,800

October 1 - 31, 2006

1,421,400

$ 45.64

1,421,400

November 1 - 30, 2006

444,900

$ 47.67

444,900

December 1 - 31, 2006

1,994,301

^(a)

$ 49.85

1,847,300

Fourth Quarter 2006

3,860,601

$ 48.05

3,713,600

Total 2006

30,566,928

$ 48.20

29,323,800

10,676,200

^(b,c)

(a)	Amount includes shares purchased from the trustee of Occidental's defined contribution savings plan totaling 413,080 shares in the first quarter, 171,946 shares in the second quarter, 511,101 shares in the third quarter and 147,001 shares in December.
(b)	In 2005, Occidental announced a common stock repurchase program. Occidental is authorized to repurchase 40 million shares of its common stock under the program.
(c)	In February 2007, Occidental increased the number of shares authorized for its previously announced share repurchase program from 40 million to 55 million.

PERFORMANCE GRAPH

The following graph compares the yearly percentage change in Occidental’s cumulative total return on its common stock with the cumulative total return of the Standard & Poor's 500 Stock Index and with that of Occidental’s peer group over the five-year period ended on December 31, 2006. The graph assumes that $100 was invested in Occidental common stock, in the stock of the companies in the Standard & Poor's 500 Index and in a portfolio of the peer group companies weighted by their relative market values each year and that all dividends were reinvested. The peer group used in the analysis consists of Anadarko Petroleum Corporation, Apache Corporation, Chevron Corporation, ConocoPhillips, Devon Energy Corporation, ExxonMobil Corporation, Hess Corporation and Occidental. The peer group changed from the prior year since certain companies which were included in the peer group have been acquired.

		12/31/2001	12/31/2002	12/31/2003	12/31/2004	12/31/2005	12/31/2006
	Occidental	$100	$111	$170	$240	$334	$415
	Peer Group	100	88	111	144	172	225
	S&P 500	100	78	100	111	117	135
The information provided in this Performance Graph shall not be deemed "soliciting material" or "filed" with the Securities and Exchange Commission or subject to Regulation 14A or 14C under the Securities Exchange Act of 1934 (Exchange Act), other than as provided in Item 201 to Regulation S-K under the Exchange Act, or subject to the liabilities of Section 18 of the Exchange Act and shall not be deemed incorporated by reference into any filing under the Securities Act of 1933 or the Exchange Act except to the extent Occidental specifically requests that it be treated as soliciting material or specifically incorporates it by reference.

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,	2006			2005			2004			2003			2002
RESULTS OF OPERATIONS ^(a)
Net sales	$	17,661		$	14,597		$	10,879		$	9,020		$	7,149
Income from continuing operations	$	4,435		$	5,040		$	2,406		$	1,559		$	1,167
Net income	$	4,182		$	5,281		$	2,568		$	1,527		$	989
Basic earnings per common share from continuing operations	$	5.20		$	6.25		$	3.04		$	2.03		$	1.55
Basic earnings per common share	$	4.90		$	6.55		$	3.24		$	1.99		$	1.31
Diluted earnings per common share	$	4.86		$	6.45		$	3.20		$	1.97		$	1.30
Core earnings ^(b)	$	4,349		$	3,732		$	2,299		$	1,599		$	1,003
FINANCIAL POSITION ^(a)
Total assets	$	32,355		$	26,108		$	21,391		$	18,168		$	16,548
Long-term debt, net and trust preferred securities ^(c)	$	2,619		$	2,873		$	3,345		$	4,446		$	4,452
Stockholders’ equity	$	19,184		$	15,032		$	10,550		$	7,929		$	6,318
MARKET CAPITALIZATION	$	42,515		$	32,129		$	23,153		$	16,349		$	10,750
CASH FLOW
Cash provided by operating activities	$	6,353		$	5,337		$	3,878		$	3,074		$	2,100
Capital expenditures	$	(3,005	)	$	(2,324	)	$	(1,720	)	$	(1,523	)	$	(1,145	)
Cash used by all other investing activities, net	$	(1,378	)	$	(837	)	$	(708	)	$	(608	)	$	(551	)
DIVIDENDS PER COMMON SHARE	$	0.80		$	0.645		$	0.55		$	0.52		$	0.50
BASIC SHARES OUTSTANDING (thousands)		852,550			806,600			791,159			767,887			752,380

(a)	See the MD&A section of this report 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 and reconciliation to net income, see "Significant Items Affecting Earnings" in the MD&A section of this report.
(c)	On January 20, 2004, Occidental redeemed the trust preferred securities.

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’s business is divided into two segments conducted through oil and gas subsidiaries and their affiliates and chemical subsidiaries and their affiliates (OxyChem).

STRATEGY
General

Occidental aims to generate superior total returns to stockholders using the following strategy:

Ø	Focus on large, long-lived oil and gas assets with long-term growth potential;
Ø	Maintain financial discipline and a strong balance sheet; and
Ø	Manage the chemical segment to provide cash in excess of normal capital expenditures.

Occidental prefers to own large, long-lived "legacy" oil and gas assets, like those in California and the Permian Basin, that tend to have moderate decline rates, enhanced secondary and tertiary recovery opportunities and economies of scale that lead to cost-effective production. Management expects such assets to contribute substantially to earnings and cash flow after invested capital.

At Occidental, maintaining financial discipline means investing capital in projects that management expects will generate above-cost-of-capital returns throughout the business cycle. During periods of high commodity prices, Occidental expects to use most of its cash flow after capital expenditures and dividends to improve the potential for future earnings by making such investments.

The chemical business is not managed with a growth strategy. Capital is expended to operate the chemical business in a safe and environmentally sound way, to sustain production capacity and to focus on projects

designed to lower manufacturing costs. Asset acquisitions may be pursued when they are expected to enhance the existing core chlor-alkali and PVC businesses. Historically, the chemical segment has generated cash flow exceeding its normal capital expenditure requirements. Occidental intends to invest this cash mainly in strategically attractive assets.

Oil and Gas

Segment Income
($ millions)

The oil and gas business seeks to add new oil and natural gas reserves at a pace ahead of production while keeping costs incurred for finding and development among the lowest in the industry. The oil and gas business implements this strategy within the limits of the overall corporate strategy primarily by:

Ø	Continuing to add commercial reserves through a combination of focused exploration and development programs conducted in and around Occidental’s core areas, which are the United States, the Middle East/North Africa and Latin America;
Ø	Pursuing commercial opportunities in core areas to enhance the development of mature fields with large volumes of remaining oil by applying appropriate technology and advanced reservoir-management practices; and
Ø	Maintaining a disciplined approach in buying and selling assets at attractive prices.

Over the past several years, Occidental has strengthened its asset base within each of the core areas. Occidental has invested in, and disposed of, assets with the goal of raising the average performance and potential of its assets. See "Oil and Gas Segment — Business Review" for a discussion of these changes.

In addition, Occidental has continued to make capital contributions and investments in the Dolphin Project in Qatar and the UAE and in Libya, and assumed operations in the Mukhaizna field in Oman for future growth opportunities, not for current production.

In 2006, Occidental acquired Vintage Petroleum, Inc. (Vintage) which it expects to provide growth in production, primarily from the Vintage Argentina assets.

Occidental’s overall performance during the past several years reflects the successful implementation of its strategy to enhance the development of mature fields, beginning with the acquisition of the Elk Hills oil and gas field in California, followed by a series of purchases in the Permian Basin in west Texas and New Mexico and the integration of the Vintage and Plains Exploration and Production Company (Plains) operations acquired in 2006.

At the end of 2006, the Elk Hills and Permian assets made up 64 percent of Occidental’s consolidated proven oil reserves and 43 percent of its consolidated proven gas reserves. On a barrels of oil equivalent (BOE) basis, they accounted for 59 percent of Occidental’s consolidated reserves. In 2006, the combined production from these assets averaged approximately 290,000 BOE per day.

Chemical

Segment Income
($ millions)

OxyChem’s strategy is to be a low-cost producer so that it can maximize its cash flow generation. OxyChem concentrates on the chlorovinyls chain beginning with chlorine, which is coproduced with caustic soda, and then chlorine and ethylene are converted, through a series of intermediate products, into polyvinyl chloride (PVC). OxyChem's focus on chlorovinyls permits it to take advantage of economies of scale.

Key Performance Indicators
General

Occidental seeks to ensure that it meets its strategic goals by continuously measuring its success in maintaining below average debt levels and top quartile performance compared to its peers in:

Ø	Total return to stockholders;
Ø	Return on equity;
Ø	Return on capital employed; and
Ø	Other segment-specific measurements such as profit per unit produced, cost to produce each unit, cash flow per unit, cost to find and develop new reserves, reserve replacement percentage and other similar measures.

Debt Structure

Occidental's total debt and total debt-to-capitalization ratios are shown in the table below:

Date ($ amounts in millions)	Total Debt		^(a)	Total Debt-to-Capitalization Ratio
12/31/02	$	4,759		43%
12/31/03	$	4,570		37%
12/31/04	$	3,905		27%
12/31/05	$	3,019		17%
12/31/06	$	2,890		13%

(a)	Includes trust preferred securities (redeemed January 20, 2004), natural gas delivery commitment (terminated in 2002), subsidiary preferred stock and capital lease obligations.

As shown, Occidental’s year-end 2006 total debt-to-capitalization ratio declined to 13 percent from the 43-percent level that existed at the end of 2002. The decrease in the total debt-to-capitalization ratio in 2006 compared with 2002 resulted from total debt reductions of 39 percent combined with an increase in stockholders' equity of 204 percent over the same period.

Since the second quarter of 2005, Occidental’s long-term senior unsecured debt has been rated A- by Standard and Poor’s Corporation, A3 by Moody’s Investors Service, A- by Fitch Ratings and A(Low) by Dominion Bond Rating Service. A security rating is not a recommendation to buy, sell or hold securities, may be subject to revision or withdrawal at any time by the assigning rating organization and should be evaluated independently of any other rating.

Return on Equity

Annual 2006 ^(a)		Three-Year Average 2004 - 2006 ^(b)
24%		30%

(a)	The Return on Equity for 2006 was calculated by dividing Occidental's 2006 earnings applicable to common stock by the average equity balance in 2006.
(b)	The three-year average Return on Equity was calculated by dividing the average earnings applicable to common stock over the three-year period 2004-2006 by the average equity balance over the same period.

Occidental has focused on achieving top quartile return on equity. In 2006, Occidental's return on equity was 24 percent and the three-year average return on equity was 30 percent. During the same three-year period, Occidental increased its stockholders’ equity by 142 percent and its quarterly dividend by 60 percent while its stock price increased by 131 percent.

OIL AND GAS SEGMENT
Business Environment

Oil and gas prices are the major variables that drive the industry’s short and intermediate term financial performance. Average yearly oil prices strengthened in 2006 over 2005 levels but ended the year even with 2005 year-end levels. During the year, Occidental experienced an increase in its price differential between the average West Texas Intermediate (WTI) price and Occidental's realized prices. Occidental’s realized price as a percentage of WTI was approximately 85 percent and 87 percent for 2006 and 2005, respectively. Prices and differentials can vary significantly, even on a short-term basis, making it difficult to forecast realized prices. The average WTI market price for 2006 was $66.23 per barrel compared with $56.56 per barrel in 2005. Occidental's average realized price for oil in 2006 was $56.57, compared with $49.18 in 2005.

The average NYMEX domestic natural gas prices decreased approximately 4 percent from 2005. For 2006, NYMEX gas prices averaged $7.82/Mcf compared with $8.11/Mcf for 2005.

Business Review

All production and reserve figures are net to Occidental unless otherwise specified.

Worldwide Production
(thousands BOE/day)

Acquisitions

In January 2006, Occidental completed the merger of Vintage into a wholly-owned Occidental subsidiary. As a result, Occidental acquired assets in Argentina, California, Yemen, Bolivia and the Permian Basin in Texas. See the applicable sections below for further information. Occidental paid $1.3 billion in cash to former Vintage shareholders, issued approximately 56 million shares of Occidental common stock, which were valued at $2.1 billion, and assumed Vintage’s debt, which had an estimated fair value of $585 million at closing. During 2006, Occidental divested a portion of Vintage’s assets for consideration of approximately $1.0 billion.

In September 2006, Occidental acquired oil and gas assets from Plains for $859 million. The principal properties acquired are adjacent to Occidental’s existing operations in California and the Permian Basin in west Texas.

Occidental’s production from the Vintage acquisition averaged 53,000 BOE per day in 2006. During the fourth quarter of 2006, production from the Plains assets averaged 6,000 BOE per day.

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. In 2006, Occidental made additional acquisitions of oil and gas producing properties near the field for approximately $434 million. Most of these properties were obtained as part of the acquisition from Plains discussed above. Oil and gas production in 2006 from these properties and the field was approximately 91,000 BOE per day. During 2006, Occidental performed infill drilling, field extensions and recompletions identified by advanced reservoir characterization techniques resulting in 277 new wells being drilled and 479 wells being worked over. In addition, an air separation unit was installed to enhance

oil recovery with nitrogen injection. As a result of these activities and acquisitions, Occidental was able to maintain production at 2005 levels. Since its acquisition, total Elk Hills oil and gas production has been approximately 301 million BOE. At the end of 2006, the property had an estimated 484 million BOE of proved reserves, compared to the 425 million BOE that were recorded at the time of the acquisition.

Permian Basin

The Permian Basin extends throughout southwest Texas and southeast New Mexico and is one of the largest and most active oil basins in the United States, with the entire basin accounting for approximately 18 percent of the total United States oil production. Occidental is the largest producer in the Permian Basin with an approximate 16-percent net share of the total Permian Basin oil production. Occidental also produces and processes natural gas and natural gas liquids (NGL) in the Permian Basin.

Most of Occidental's Permian Basin interests were obtained through the acquisition of Altura in 2000 for approximately $3.6 billion. In 2005 and 2006, Occidental made several additional acquisitions of oil and gas producing property interests for approximately $1.7 billion and $290 million (including approximately $175 million related to the acquisition of Vintage and the property acquisitions from Plains), respectively.

Occidental's total share of Permian Basin oil, gas and NGL production averaged 199,000 BOE per day in 2006 compared to 189,000 BOE per day in 2005. At the end of 2006, Occidental's Permian Basin properties had 1.2 billion BOE in proved reserves. Occidental's Permian Basin production is diversified across a large number of producing areas. The largest producing areas in 2006 included Wasson San Andres, Slaughter, Levelland, North Cowden, Wasson Clearfork and Salt Creek, which contributed 20 percent, 9 percent, 5 percent, 4 percent, 4 percent and 4 percent, respectively, to Occidental’s 2006 Permian BOE production.

Occidental’s interests in the Permian Basin offer additional development and exploitation potential. During 2006, Occidental drilled approximately 260 wells on its operated properties and participated in wells drilled on outside operated interests. Occidental conducted significant development activity on eight carbon dioxide (CO2) projects during 2006, including implementation of new floods and expansion of existing CO2 floods. Occidental also focused on improving the performance of existing wells. Occidental had an average of 122 well service units working in the Permian area during 2006 performing well maintenance and workovers.

Approximately 60 percent of Occidental’s Permian Basin oil production is from fields that actively employ the application of CO2 flood technology, an enhanced oil recovery (EOR) technique. This involves injecting CO2 into oil reservoirs where it acts as a solvent, causing the oil to flow more freely into producing wells. These CO2 flood operations make Occidental a world leader in the application of this technology.

Vintage California

In 2006, Occidental combined its California properties acquired from Vintage and Plains with existing California properties (excluding the Elk Hills, THUMS and Tidelands Oil Production Company (Tidelands) properties). The combined properties produce oil and gas from more than 50 fields, spread over 500 miles mainly in the Ventura, San Joaquin and Sacramento basins. Oil and gas average production in 2006 was approximately 17,000 BOE per day. At the end of 2006, the combined properties had an estimated 128 million BOE of proved reserves.

THUMS

Occidental purchased THUMS, the field contractor for an oil production unit offshore Long Beach, California, in 2000. Since then, Occidental has implemented a successful development plan. Occidental's share of production from THUMS is subject to contractual arrangements similar to a production sharing contract (PSC), whereby Occidental’s share of production varies inversely with oil prices. For 2006, production from THUMS averaged 19,000 BOE per day.

Gulf of Mexico

Occidental has a one-third interest in the deep-water Horn Mountain oil field, which is Occidental's only property in the Gulf of Mexico. BP p.l.c. (BP) is the operator. For 2006, Occidental's production at Horn Mountain averaged 13,000 BOE per day.

Hugoton and Other

Occidental owns a large concentration of gas reserves, production interests and royalty interests in the Hugoton area of Kansas and Oklahoma.

Also, Occidental has over 28,000 net acres in the Piceance Basin in western Colorado. During 2006, Occidental drilled 43 development wells and started operation of a newly constructed gas processing facility.

Occidental acquired Tidelands in 2006. Tidelands is the field contractor for an onshore oil production unit in Long Beach, California. Occidental’s share of production from Tidelands is subject to contractual arrangements similar to a PSC, whereby Occidental’s share of production varies inversely with oil prices. Tidelands also is subject to cost-plus contracts.

Occidental’s Hugoton and other operations produced 26,000 BOE per day.

Middle East/North Africa
Dolphin Project

Occidental's investment in the Dolphin Project, which was acquired in 2002, consists of two separate economic interests held through two separate legal entities. One entity, OXY Dolphin E&P, LLC, owns a 24.5-percent undivided interest in the assets and liabilities associated with a Development and Production Sharing Agreement (DPSA) with the Government of Qatar to develop and produce natural gas and condensate in Qatar’s North Field for 25 years from the start of production, with a provision to request a 5-year extension. The purchase price of the undivided working interest in the DPSA was approximately $60 million and was recorded in property, plant & equipment (PP&E). This undivided interest is proportionately consolidated in Occidental's financial statements.

A second entity, OXY Dolphin Pipeline, LLC, owns 24.5 percent of the stock of Dolphin Energy Limited (Dolphin Energy). The purchase price of Dolphin Energy stock totaled approximately $250 million and was recorded as an equity investment.

Dolphin Energy is the operator under the DPSA on behalf of the three DPSA participants, including Occidental. Dolphin Energy also has the rights to build, own and operate a 260-mile-long, 48-inch natural gas pipeline, which will transport dry natural gas from Qatar to the UAE.

The Dolphin Project is expected to cost approximately $4.8 billion in total, including investments in the local UAE eastern gas distribution system and the Al Ain-Fujairah pipelines, which were added to improve the natural gas distribution system but were not contained in the original scope of the Dolphin Project. Occidental expects to invest approximately $1.2 billion of this total. The project is being financed by a combination of participant investment and project financing. During 2007, Occidental expects to spend a combined total of approximately $185 million for the gas exploration and development activity and the investment in Dolphin Energy, compared to $361 million in 2006.

In 2003, the Government of Qatar approved the final field development plan for the Dolphin Project. Construction of an onshore gas processing and compression plant at Ras Laffan in Qatar commenced in 2004 and is continuing. The pipeline is projected to start up with temporary third-party gas volumes in the first quarter of 2007. The gas volumes produced under the Dolphin DPSA are expected to replace the temporary third-party gas commencing with the start-up of the onshore gas plant in mid-2007.

Based on existing supply contracts, the Dolphin Project is expected to export approximately 2.0 billion cubic feet (Bcf) of natural gas per day (plus associated liquids and byproducts). However, the pipeline is expected to have capacity to transport up to 3.2 Bcf of natural gas per day. Demand for natural gas in the UAE and Oman continues to grow and Dolphin Energy’s customers have requested additional gas supplies. To help fulfill this growing demand, Dolphin Energy will continue to pursue an agreement to secure an additional supply of gas from Qatar.

To date, Occidental has recorded 265 million BOE of proved oil and gas reserves for the Dolphin Project DPSA activity. Proved developed, non-producing oil and gas reserves are 133 million BOE, with the rest included in proved undeveloped reserves. No revenue or production costs were recorded in 2006 for the Dolphin Project gas exploration and development activity.

Qatar

In addition to the Dolphin Project, Occidental participates in two production projects in Qatar: Idd El Shargi North Dome (ISND) and Idd El Shargi South Dome (ISSD). Occidental continues to target the development and recovery of additional reserves in both the ISND and ISSD fields by applying advanced drilling systems and improved reservoir management techniques. Capital expenditures in Qatar for the ISSD and ISND projects were $257 million in 2006.

Occidental’s net share of combined production from the two fields averaged 43,000 barrels per day in 2006.

Yemen

Occidental owns interests in four blocks in Yemen, including a 38-percent direct-working interest in the Masila fields, a 40.4-percent interest in the East Shabwa field, comprising a 28.6-percent direct-working interest and an 11.8-percent equity interest in an unconsolidated entity, and a 75-percent interest in Block S-1, which was part of the Vintage acquisition. Average production was 30,000 barrels of oil per day in 2006, with 19,000 coming from Masila, 6,500 from East Shabwa and the remainder from Block S-1. In addition, Occidental owns and operates an 80-percent working interest in Block 20 and is finalizing the PSC for Block 75, which was acquired in an exploration bid round.

Oman

Occidental's Oman business includes Block 9 and Block 27, where it holds a 65-percent working interest in each, Block 53, where it holds a 45-percent working interest and Block 54, where it holds a 70-percent working interest. Occidental is the operator of all four blocks where production averaged 23,000 BOE per day in 2006, with 19,000 BOE coming from Block 9, 3,000 BOE from Block 53 and the remainder from Block 27. The Block 9 agreement provides for two ten-year extensions and Occidental has agreed with the Government of Oman to the first ten-year extension through December 7, 2015.

Occidental (and its Block 53 partners) signed a new PSC for the Mukhaizna field with the Government of Oman in 2005. In September 2005, Occidental assumed operations of the Mukhaizna field, where it holds a 45-percent working interest. The Mukhaizna field, located in Oman’s south central interior, was discovered in 1975 and was brought into production in 2000. Primary production peaked in the same year at 15,000 barrels of oil per day and by September 2005, had declined to 8,500 barrels of oil per day. By the end of 2006, Occidental had increased gross production to 11,000 barrels of oil per day. Occidental plans to use horizontal well steamflood technology to steadily increase production.

In October 2005, Occidental received approval for development of the Khamilah field in Block 27. The exploitation term of the agreement is 30 years beginning in September 2005. Occidental began production in June 2006, well ahead of the planned start-up timing of October 2006.

Occidental (and its Block 54 partners) signed a new PSC for Block 54 with the Government of Oman in June 2006. The initial exploration phase is four years beginning in July 2006.

In March 2004, Occidental began selling gas from Block 9 to the Government of Oman under a gas sales agreement. Under the agreement, Occidental (and its Block 9 partner) must supply approximately 114 MMcf per day of natural gas until December 31, 2007. Occidental’s minimum delivery obligation is approximately 89 percent of the expected average gross production. In 2006, Occidental (and its partner) supplied an average of approximately 116 MMcf per day of natural gas under the agreement. As of December 31, 2006, the gross proved gas reserves from Block 9 comprise approximately 590 percent of the minimum gas still to be delivered under the agreement.

Libya

Occidental suspended all activities in Libya in 1986 as a result of economic sanctions imposed by the United States government. During the imposition of sanctions, Occidental derived no economic benefit from its Libyan interests. In 2004, the United States government lifted all of the principal economic sanctions against Libya.

In 2006, the United States effectively eliminated the last of the economic sanctions.

In 2005, the Libyan authorities approved the terms of Occidental’s participation in the assets that it left in 1986. This re-entry agreement allowed Occidental to return to its Libyan operations on generally the same terms in effect when activities were suspended. Those assets consist of three producing contracts in the Sirte Basin and four exploration blocks. Occidental paid approximately $133 million in re-entry bonuses, capital adjustment and work-in-progress payments and is required to pay $10 million per year while it continues to operate in Libya, as reimbursements for past development costs associated with these assets. In addition, Occidental committed to spend $90 million over the next five years in the four exploration blocks. Currently, Occidental’s rights in the producing fields extend through 2009 and early 2010. Occidental had its first lifting from its Libyan operations in September 2005 and production during 2006 averaged 23,000 BOE per day.

Separately, in early 2005, Occidental participated in the EPSA IV exploration bid round in Libya. Occidental successfully bid on nine of the 15 areas available. Occidental is the operator for five onshore areas and has a 90-percent exploration working interest in each area. In addition, Occidental holds a 35-percent exploration working interest in four offshore areas. Woodside Petroleum Ltd. is the operator for the offshore areas. Occidental paid approximately $90 million in exploration lease bonuses for these nine new areas and committed to perform a minimum exploration work program valued at $125 million over the commitment period.

In 2006, approximately 10,000 kilometers of seismic data was acquired for the onshore areas which will provide the basis for analysis and selection of the initial exploration prospects to be drilled by Occidental. Onshore seismic acquisition and analysis activity is planned to continue into 2007. In the offshore areas, the operator acquired approximately 9,400 kilometers of seismic data in preparation for the planned 2007 drilling program.

In November 2006, Occidental commenced drilling of the first exploration well in the onshore program, which is undergoing evaluation. A second rig is expected to begin drilling in the first quarter of 2007 and a substantial portion of the exploration drilling obligations is expected to be completed during the next 18-month period.

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. Occidental’s share of production was approximately 17,000 BOE per day in 2006.

Russia

In January 2007, Occidental sold its 50-percent interest in the Vanyoganneft joint venture to TNK-BP for approximately $485 million. At year-end, Occidental's proved Vanyoganneft reserves were an estimated 33 million BOE and its production was approximately 27,000 BOE per day in 2006. Occidental recorded a gain of approximately $400 million resulting from the sale in the first quarter of 2007.

Latin America
Argentina

Substantially all of Occidental’s Argentina assets were obtained as part of the acquisition of Vintage in 2006. The assets consist of 22 concessions, 19 of which Occidental operates with a 100-percent working interest, located in the San Jorge Basin in Southern Argentina and the Cuyo Basin and Neuquén Basin in Western Argentina.

During 2006, Occidental drilled 135 new wells and performed a number of recompletions and well repairs. Occidental expects to significantly increase production over the next five years through aggressive drilling, waterflooding and EOR projects. Occidental is planning to drill 190 wells and implement a number of waterflood projects in 2007.

Occidental’s share of production from Argentina averaged 36,000 BOE per day in 2006.

Bolivia

In 2006, Occidental’s operating subsidiary acquired working interests in four Blocks located in the Tarija, Chuquisaca and Santa Cruz regions of Bolivia as part of the Vintage acquisition. Production for 2006 was approximately 3,000 BOE per day. In 2006, Bolivia initiated a nationalization process pursuant to which Occidental's operating subsidiary entered into two new operations contracts with commercial terms that, among other things, provide Bolivia greater operational control and control over the commercialization of hydrocarbons.

Colombia

Occidental is the operator of the Caño Limón field where its share of production averaged 28,000 barrels of oil per day in 2006. Colombia's national oil company, Ecopetrol, operates the Caño Limón-Coveñas oil pipeline and marine-export terminal. The pipeline transports oil produced from the Caño Limón field for export to international markets.

In 2005, Ecopetrol approved development of the Caricare field, an exploration discovery under the Rondon Association Contract, adjacent to Caño Limón. Production from this field, where Occidental holds a 35-percent working interest, commenced in May 2006. Production from the field and two adjacent fields was 4,000 BOE per day in 2006.

In 2005, Occidental signed a new agreement with Ecopetrol for an EOR project in the La Cira-Infantas field, located in central Colombia. In December 2006, Occidental completed the second pilot phase and agreed with Ecopetrol to enter into a third and commercial phase of the project. In 2006, Occidental’s share of production was 1,000 BOE per day. Production from La Cira-Infantas is transported by the Ecopetrol pipeline and sold to an Ecopetrol refinery.

Additionally, Occidental holds various working interests in eight exploration blocks.

Ecuador

In May 2006, Ecuador terminated Occidental's contract for the operation of Block 15, which comprised all of its oil-producing operations in the country, and seized Occidental's Block 15 assets. The process resulting in this action began shortly after Occidental prevailed, by unanimous decision of an international arbitration panel subsequently upheld by a London court, in a legal dispute over tax refunds that Ecuador wrongfully withheld. Occidental immediately filed an arbitration claim against Ecuador, seeking redress for illegal confiscation of the Block 15 operations with the International Centre for Settlement of Investment Disputes in Washington, D.C., invoking the protections of the U.S. - Ecuador Bilateral Investment Treaty. As a result of the seizure, Occidental classified its Block 15 operations as discontinued operations. In 2006, Occidental recorded a net after-tax charge of $296 million in discontinued operations. This amount consists of after-tax charges for the write-off of the investment in Block 15 in Ecuador, as well as ship-or-pay obligations entered into with respect to the Oleoducto de Crudos Pesados, Ltd. (OCP) pipeline in Ecuador to ship oil produced in Block 15, partially offset by $109 million after-tax income from operations for the first five months of 2006. Occidental’s Block 15 assets and liabilities are classified as assets and liabilities of discontinued operations on the consolidated balance sheets on a retrospective basis.

In addition, Occidental has a 14-percent interest in the OCP oil export pipeline. See also "Off-Balance-Sheet Arrangements — Ecuador" for further information about the OCP pipeline.

Production-Sharing Contracts

Occidental conducts its operations in Qatar, Oman and Yemen under PSCs and, under such contracts, receives a share of production to recover its costs and an additional share for profit. In addition, Occidental's share of production from THUMS and Tidelands are subject to contractual arrangements similar to a PSC. 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.

Proved Reserves - Evaluation and Review Process

A senior corporate officer of Occidental is responsible for the internal audit and review of its oil and gas reserves data. In addition, a Corporate Reserves Review Committee (Reserves Committee) has been established, consisting of senior corporate officers, to monitor and review Occidental's oil and gas reserves. The Reserves Committee reports to the Audit Committee of Occidental's Board of Directors periodically throughout the year. Occidental has retained Ryder Scott Company, L.P. (Ryder Scott), independent petroleum engineering consultants, to review its annual oil and gas reserve estimation processes since 2004.

Again in 2006, Ryder Scott has compared Occidental’s methods and procedures for estimating oil and gas reserves to generally accepted industry standards and has reviewed certain data, methods and procedures used in estimating reserves volumes, the economic evaluations and reserves classifications. Ryder Scott reviewed the specific application of such methods and procedures for a selection of oil and gas fields considered to be a valid representation of Occidental’s total reserves portfolio. In 2006, Ryder Scott reviewed 10.5 percent of Occidental’s oil and gas reserves. Since being engaged in 2004, Ryder Scott has reviewed Occidental’s reserve estimation methods and procedures for approximately 49 percent of Occidental’s oil and gas reserves.

Based on this review, including the data, technical processes and interpretations presented by Occidental, Ryder Scott has concluded that the methodologies used by Occidental in preparing the relevant estimates generally comply with current Securities and Exchange Commission (SEC) standards. Ryder Scott has not been engaged to render an opinion as to the reserves volumes reported by Occidental.

Proved Reserve Additions

Occidental consolidated subsidiaries had proved reserves at year-end 2006 of 2,869 million BOE, as compared with the year-end 2005 amount of 2,566 million BOE. Additionally, Occidental’s investments in other interests had proved reserves of 30 million and 45 million BOE at year-end 2006 and 2005, respectively. The increase in the consolidated subsidiaries’ reserves from all sources was 518 million BOE, of which 289 million BOE were from proved developed reserves and 229 million BOE were from proved undeveloped reserves.

Proved developed reserves represent approximately 78 percent of Occidental’s total proved reserves at year-end 2006 compared to 74 percent at year-end 2005.

Proved Reserve Additions - Consolidated Subsidiaries - 2006

In Millions of BOE	Proved Developed		Proved Undeveloped	Proved Total
Revisions of previous estimates	(5	)	22	17
Improved Recovery	40		101	141
Extensions and Discoveries	22		12	34
Purchases	232		94	326
Total Additions	289		229	518

Proved reserves consist of 78 percent crude oil and condensate and 22 percent natural gas.

Revisions of Previous Estimates

In 2006, Occidental added net reserves of 17 million BOE through revisions of previous estimates, primarily in Libya, the Dolphin Project and Argentina, partially offset by negative revisions in the United States reflecting a reduction in gas prices. Oil price changes would affect proved reserves recorded by Occidental. For example, if oil prices increased by $5 per barrel, less oil volume is required to recover costs, and PSCs would reduce Occidental's share of proved reserves by approximately 9 million BOE. Conversely, if oil prices dropped by $5 per barrel, Occidental's share of proved reserves would increase by a similar amount. Oil price changes would also tend to affect the economic lives of proved reserves from other contracts, in a manner partially offsetting the PSC reserve volume changes. Apart from the effects of product prices, Occidental's approach to interpreting technical data regarding oil and gas reserves makes it more likely future reserve revisions will be positive rather than negative.

Improved Recovery

In 2006, Occidental added reserves of 141 million BOE through improved recovery. In the United States, improved recovery additions were 43 million BOE in the Permian Basin and 28 million BOE in the Elk Hills field. Foreign additions included 23 million BOE in Argentina and 11 million BOE in Colombia. The Elk Hills operations employ infill drilling and both gas flood and water flood techniques. In the Permian Basin, the increased reserves were primarily attributable to enhanced recovery techniques, such as drilling additional CO2 flood and water flood wells.

Extensions and Discoveries

Occidental obtains reserve additions from extensions and discoveries, which are dependent on successful exploitation programs. In 2006, as a result of such programs, Occidental added reserves of 34 million BOE, consisting of 13 million BOE in the United States, 14 million BOE in the Middle East/North Africa and 7 million BOE in Argentina. In western Colorado, Occidental added approximately 4 million BOE from the extension of gas reserves, most of which will require additional development capital.

The success of improved recovery, extension and discovery projects depends on reservoir characteristics and technology improvements, as well as oil and gas prices, capital costs and operating costs. Many of these factors are outside of management's control, and will affect whether or not these historical sources of reserve additions continue at similar levels.

Purchases of Proved Reserves

In 2006, Occidental purchased reserves of 326 million BOE, of which 143 million BOE were in the United States and 178 million BOE were in Latin America. The Vintage acquisition added proved reserves of 160 million BOE in Argentina and 8 million BOE in Bolivia with the remainder in the United States and Yemen, of which 66 percent were proved developed reserves. Occidental continues to add reserves through acquisitions when properties are available at reasonable prices. Acquisitions are dependent on successful bidding and negotiating of oil and gas contracts at attractive terms. As market conditions change, the available supply of properties may increase or decrease accordingly.

Proved Undeveloped Reserves

Occidental had proved undeveloped reserve additions of 207 million BOE resulting from improved recovery, extensions and discoveries and purchases, primarily in Argentina, the Permian Basin and the Elk Hills field. Argentina provided 46 percent of this increase. These proved undeveloped reserve additions were offset by reserve transfers of 275 million BOE to the proved developed category as a result of 2006 development programs. The Dolphin Project transferred 133 million BOE to the proved developed category during 2006. This transfer, along with other revisions, reduced the Dolphin Project's proved undeveloped reserves to 132 million BOE at December 31, 2006 from 250 million BOE at December 31, 2005. Overall, Occidental's proved undeveloped reserves decreased by 47 million BOE in 2006.

Industry Outlook

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.

Worldwide oil prices in 2006 remained at or near historical highs during the first three quarters of the year, but fell in the fourth quarter. Continued economic growth, resulting in increased demand, and concerns about supply availability, could result in continued high prices. A lower demand growth rate could result in lower crude oil prices.

Oil prices have significantly affected profitability and returns for Occidental and other upstream producers. Oil prices cannot be predicted with any certainty. The WTI price has averaged approximately $33 per barrel over the past ten years. However, the industry has historically experienced wide fluctuations in prices. During 2006, Occidental experienced an increase in its price differential of the average WTI price over Occidental's realized prices. See the "Oil and Gas Segment — Business Environment" section above for further information.

While local 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, making it difficult to forecast prices with any degree of confidence. Over the last ten years, the NYMEX gas price has averaged approximately $4.60 per Mcf.

CHEMICAL SEGMENT
Business Environment

The chemical segment results improved in 2006 due to better margins despite higher feedstock costs. OxyChem also benefited from the mid-year 2005 acquisition of two basic chemical manufacturing facilities from Vulcan Materials Company (Vulcan) and realized substantial synergies and higher sales volumes.

Business Review
Basic Chemicals

During 2006, demand and pricing for basic chemical products generally remained strong while energy costs fell, which enabled OxyChem to realize above average margins. OxyChem’s chlor-alkali operating rate for 2006 was 91 percent, just slightly above the industry average operating rate of 90 percent. Industry demand for liquid caustic soda in 2006 was virtually flat compared to the prior year. Demand increased in the refining industry but was offset by reduced demand primarily in the organics and inorganics chemical market segments. Industry pricing for caustic soda started the year strong, but subsequently softened throughout the first three quarters of 2006. Caustic soda supply tightened in the fourth quarter due to lower chlorine demand resulting from a weakening vinyls sector and lower imports of caustic soda. This led to caustic soda price stabilization in the fourth quarter.

Vinyls

The PVC industry realized record level pricing and margins for 2006. Ethylene cost increases of 9 percent were partially offset by lower natural gas prices. Total PVC industry-wide demand in 2006 was 3 percent lower as compared with 2005. OxyChem operated its PVC facilities at an average operating rate of 82 percent for 2006, compared to the North American industry average of 87 percent.

Industry Outlook

In 2006, Occidental's chemical business core earnings increased by 16 percent compared to 2005, primarily due to the continued strong United States economy, higher sales volumes, largely due to the full year impact of the Vulcan operating assets, and improving margins.

Future performance will depend on global economic activity, the competitiveness of the United States in the world economy, feedstock and energy pricing, and the impact of additional production capacity entering the market place.

Basic Chemicals

Forecasts of a slowing economy offset by a stabilizing residential construction market in 2007 are expected to result in demand levels similar to average 2006 levels. Despite first quarter pressure on pricing from a weak vinyls market, margins in 2007 are expected to remain strong, but could weaken in the fourth quarter due to the anticipated impact of capacity additions in late 2007.

Vinyls

Industry-wide PVC operating rates are expected to be lower in 2007 as a result of weak demand in the first quarter coupled with the start-up of new capacity later in the year.

Lower cost Far East Asian PVC production has resulted in a significant increase in imports of PVC and finished goods into the Western Hemisphere.

CORPORATE AND OTHER

Corporate and Other includes the investments in Lyondell Chemical Company (Lyondell) and Premcor, Inc., (Premcor), a leased cogeneration facility in Taft, Louisiana and a 1,300-mile oil pipeline and gathering system located in the Permian Basin, which is used in corporate-directed oil and gas marketing and trading operations. It also includes a cogeneration facility at Ingleside, Texas, in which Occidental held a 50-percent interest, and acquired the remaining 50-percent interest in October 2006. The Premcor investment was sold in 2005.

Since December 31, 2006, Occidental has resolved certain legal disputes that it expects will result in a gain of approximately $108 million in the first quarter of 2007.

On August 1, 2006, Occidental effected a two-for-one stock split in the form of a stock dividend to shareholders of record as of that date with distribution of the shares on August 15, 2006. All share and per share amounts discussed and disclosed in this Annual Report on Form 10-K reflect the effect of the stock split.

Lyondell

In May 2006, Occidental lost significant influence over Lyondell and classified its Lyondell shares as an available-for-sale investment. In October 2006, Occidental sold 10 million shares of Lyondell's common stock in a registered public offering for a pre-tax gain of $90 million and gross proceeds of $250 million. At December 31, 2006, Occidental owned 20.3 million Lyondell shares of common stock (8-percent ownership), with a carrying value of $519 million, and warrants to purchase an additional five million shares of Lyondell common stock. In February 2007, Occidental exercised these warrants and received approximately 700,000 shares of Lyondell stock. Following this transaction, Occidental owned approximately 21 million shares of Lyondell common stock.

Premcor

Valero Energy Corp.’s (Valero) acquisition of Premcor resulted in a $704 million pre-tax gain and the subsequent sale of all of the Valero shares received resulted in an additional $22 million pre-tax gain in 2005.

SEGMENT RESULTS OF 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 generally exclude income taxes, interest income, interest expense, environmental remediation expenses, 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 and other earnings from the segments' equity investments.

The following table sets forth the sales and earnings of each operating segment and corporate items:

In millions, except per share amounts For the years ended December 31,	2006			2005			2004
SALES
Oil and Gas	$	12,676		$	9,805		$	7,093
Chemical		4,815			4,641			3,675
Other ^(a)		170			151			111
	$	17,661		$	14,597		$	10,879
EARNINGS(LOSS)
Oil and Gas ^(b)	$	7,239		$	5,968		$	4,021
Chemical ^(c)		901			607			414
		8,140			6,575			4,435
Unallocated corporate items
Interest expense, net ^(d)		(131	)		(201	)		(240	)
Income taxes ^(e)		(3,466	)		(1,927	)		(1,639	)
Other ^(f)		(108	)		593			(150	)
Income from continuing operations		4,435			5,040			2,406
Discontinued operations, net ^(g)		(253	)		238			162
Cumulative effect of changes in accounting principles, net		—			3			—
Net Income	$	4,182		$	5,281		$	2,568
Basic Earnings per Common Share	$	4.90		$	6.55		$	3.24

(a)	These amounts represent revenue from a Taft, Louisiana cogeneration plant and the Permian Basin pipeline and gathering system.
(b)	The 2006, 2005 and 2004 amounts include interest income of $10 million, $11 million and $18 million, respectively, from loans made to an equity investee.
(c)	The 2005 amount includes a $139 million charge for the write-off of two previously idled chemical plants and one operating plant and an additional charge of $20 million for the write-down of another chemical plant.
(d)	The 2006, 2005 and 2004 amounts include $31 million, $42 million and $17 million, respectively, of interest charges to redeem or purchase and retire various debt issues.
(e)	As a result of changes in compensation programs in 2006, Occidental wrote off approximately $40 million of the related deferred tax asset that had been recognized in the financial statements prior to the changes. The 2005 amount includes a $335 million tax benefit due to the reversal of tax reserves no longer required, a $619 million tax benefit resulting from a closing agreement with the U.S. Internal Revenue Service resolving certain foreign tax credit issues and a $10 million charge related to a state income tax issue. The 2004 amount includes $47 million of credits related to tax settlements with the IRS.
(f)	The 2006 amount includes a $90 million pre-tax gain from the sale of 10 million shares of Lyondell, a $108 million pre-tax gain related to litigation settlements, $54 million of corporate equity-method investment income and $47 million of environmental remediation expenses. The 2005 amount includes a $726 million pre-tax gain from Valero’s acquisition of Premcor and the subsequent sale of the Valero shares received, a $140 million pre-tax gain from the sale of 11 million shares of Lyondell common stock, $71 million of corporate equity-method investment income and $62 million of environmental remediation expense. The 2004 amount includes a $121 million pre-tax gain on the issuance of Lyondell common stock, $12 million of corporate equity-method investment income and $59 million of environmental remediation expense.
(g)	In the second quarter of 2006, Ecuador’s Minister of Energy terminated Occidental’s contract for the operation of Block 15 and the Government of Ecuador seized Occidental’s Block 15 assets shortly thereafter. As a result of the seizure, Occidental has classified its Block 15 operations as discontinued operations on a retrospective application basis. The 2006 discontinued operations amount also includes income from Vintage properties that were held for sale. The 2004 amount also includes the specialty resins business that was classified as a discontinued operation in 2004.

Oil and Gas

In millions, except as indicated	2006			2005			2004
Segment Sales	$	12,676		$	9,805		$	7,093
Segment Earnings	$	7,239		$	5,968		$	4,021
Core Earnings ^(a)	$	7,239		$	6,012		$	4,021
Net Production per Day
United States
Crude oil and liquids (MBBL)
California		86			76			78
Permian		167			161			154
Horn Mountain		12			13			19
Hugoton and other	3			3			3
Total		268			253			254
Natural Gas (MMCF)
California		256			242			237
Hugoton and other		138			133			127
Permian		194			170			130
Horn Mountain	7			8			13
Total		595			553			507
Latin America
Crude oil (MBBL)
Argentina		33			—			—
Colombia	38			36			37
Total		71			36			37
Natural Gas (MMCF)
Argentina		17			—			—
Bolivia	17			—			—
Total		34			—			—
Middle East/North Africa
Crude oil (MBBL)
Oman		18			17			13
Qatar		43			42			45
Yemen		29			28			32
Libya	23			8			—
Total		113			95			90
Natural Gas (MMCF)
Oman		30			44			55
Other Eastern Hemisphere
Crude oil (MBBL)
Pakistan		4			5			7
Natural Gas (MMCF)
Pakistan		76			77			75
Barrels of Oil Equivalent (MBOE) ^(b)
Subtotal Consolidated Subsidiaries		578			501			494
Colombia-minority interest		(5	)		(4	)		(4	)
Russia-Occidental net interest ^(c)		27			28			29
Yemen-Occidental net interest	1			1			1
Total Worldwide Production (MBOE) ^(d)		601			526			520
(See footnotes on next page)

Oil and Gas (continued)

In millions, except as indicated	2006		2005		2004
Average Sales Prices
Crude Oil Prices ($ per bbl)
United States	$	58.13	$	50.21	$	37.72
Latin America	$	52.40	$	51.18	$	36.85
Middle East/North Africa ^(e)	$	61.58	$	49.88	$	34.88
Other Eastern Hemisphere	$	56.70	$	46.84	$	33.13
Total consolidated subsidiaries	$	57.95	$	50.19	$	36.79
Other interests	$	34.25	$	36.16	$	23.83
Total worldwide ^(d)	$	56.57	$	49.18	$	35.79
Gas Prices ($ per Mcf)
United States	$	6.51	$	7.11	$	5.35
Latin America	$	2.00	$	—	$	—
Middle East/North Africa ^(e)	$	0.97	$	0.96	$	0.97
Other Eastern Hemisphere	$	2.94	$	2.44	$	2.25
Total consolidated subsidiaries	$	5.66	$	6.11	$	4.56
Other interests	$	0.14	$	0.16	$	—
Total worldwide ^(d)	$	5.50	$	5.98	$	4.56
Expensed Exploration ^(f)	$	295	$	314	$	214
Capital Expenditures
Development	$	2,394	$	1,769	$	1,335
Exploration	$	132	$	258	$	83
Other ^(g)	$	195	$	110	$	108

(a)	For an explanation of core earnings and reconciliation to net income, see "Significant Items Affecting Earnings."
(b)	Natural gas volumes have been converted to equivalent BOE based on energy content of 6,000 cubic feet (one thousand cubic feet is referred to as a “Mcf”) of gas to one barrel of oil.
(c)	Sold in January 2007.
(d)	Occidental has classified its Ecuador Block 15 operations as discontinued operations on a retrospective application basis and excluded them from this table. Excluded production from the Block 15 operations averaged 43,000 BOE per day for the first five months of 2006, 42,000 BOE per day in 2005 and 46,000 BOE per day in 2004.
(e)	These prices exclude the impact of taxes owed by Occidental but paid by governmental entities on its behalf.
(f)	Includes dry hole write-offs and lease impairments of $114 million in 2006, $220 million in 2005 and $155 million in 2004.
(g)	Includes capitalized portion of injected CO2 of $64 million, $59 million and $54 million in 2006, 2005 and 2004, respectively. Excludes acquisitions.

Core earnings in 2006 were $7.2 billion, compared to $6.0 billion in 2005. The increase in core earnings is primarily due to higher crude oil prices and oil and gas production, partially offset by higher operating expenses, including a depreciation, depletion and amortization (DD&A) increase, which was driven by higher volumes and rates.

Core earnings in 2005 were $6.0 billion, compared with $4.0 billion in 2004. The increase in core earnings is primarily due to higher prices and volumes for crude oil and natural gas, partially offset by higher operating expenses, higher exploration expense and increased DD&A rates.

Average consolidated production costs for 2006 were $11.23 per BOE, compared to the average 2005 production cost of $8.81 per BOE. At least 41 percent of the increase was a result of higher energy prices pushing up utility costs, gas plant costs and ad valorem and export taxes, and the impact on Occidental's PSCs of lower volumes due to higher energy prices. These cash operating cost increases included $0.57 per barrel for taxes and $0.33 per barrel for higher energy costs. The remaining increase of $1.52 per barrel was the result of higher workover, maintenance and lifting costs. Maintenance costs increased by $116 million, while workovers, ad valorem taxes and utilities each accounted for approximately $55 million in higher costs during 2006.

Also, see "Production-Sharing Contracts" above.

Chemical

In millions	2006		2005		2004
Segment Sales	$	4,815	$	4,641	$	3,675
Segment Earnings	$	901	$	607	$	414
Core Earnings ^(a)	$	901	$	777	$	414
Capital Expenditures	$	251	$	173	$	155

(a)	For an explanation of core earnings and reconciliation to net income, see "Significant Items Affecting Earnings."

Core earnings in 2006 were $901 million, compared to $777 million in 2005. The increase in core earnings is primarily due to higher margins in chlorine, caustic soda and PVC.

Core earnings in 2005 were $777 million, compared with $414 million in 2004. The increase in core earnings is primarily due to higher margins resulting from higher prices for chlorine, caustic soda and PVC, partially offset by higher energy and feedstock 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-Generally Accepted Accounting Principles (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 GAAP.

Significant Items Affecting Earnings

Benefit (Charge) (in millions)	2006			2005			2004
NET INCOME	$	4,182		$	5,281		$	2,568
OIL AND GAS
Segment Earnings	$	7,239		$	5,968		$	4,021
Less:
Contract settlement		—			(26	)		—
Hurricane insurance charge	—			(18		)	—
Segment Core Earnings	$	7,239		$	6,012		$	4,021
CHEMICAL
Segment Earnings	$	901		$	607		$	414
Less:
Write-off of plants		—			(159	)		—
Hurricane insurance charge	—			(11		)	—
Segment Core Earnings	$	901		$	777		$	414
TOTAL SEGMENT CORE EARNINGS	$	8,140		$	6,789		$	4,435
CORPORATE
Results ^(a)	$	(3,958	)	$	(1,294	)	$	(1,867	)
Less:
Debt purchase expense		(31	)		(42	)		—
Trust preferred redemption charge		—			—			(11	)
Gain on sale of Lyondell shares		90			140			—
Gain on sale of Premcor-Valero shares		—			726			—
Gain on Lyondell stock issuance		—			—			121
State tax issue charge ^(b)		—			(10	)		—
Settlement of federal tax issue ^(b)		—			619			47
Reversal of tax reserves ^(b)		—			335			—
Deferred tax write-off due to compensation program changes ^(b)		(40	)		—			—
Equity investment impairment		—			(15	)		—
Equity investment hurricane insurance charge		—			(2	)		—
Hurricane insurance charge		—			(10	)		(15	)
Litigation settlements		108			—			—
Tax effect of pre-tax adjustments		(41	)		(219	)		(35	)
Discontinued operations, net of tax ^(b)		(253	)		238			162
Cumulative effect of changes in accounting principles, net of tax ^(b)		—			3			—
CORPORATE CORE RESULTS	$	(3,791	)	$	(3,057	)	$	(2,136	)
TOTAL CORE EARNINGS	$	4,349		$	3,732		$	2,299

(a)	Includes net interest expense, income taxes, general and administrative and other expense, and certain non-core items.
(b)	Amounts shown after tax.

TAXES

Deferred tax liabilities, net of deferred tax assets of $1.4 billion, were $2.1 billion at December 31, 2006. The current portion of the deferred tax assets of $190 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 temporary differences.

Worldwide Effective Tax Rate

The following table sets forth the calculation of the worldwide effective tax rate for reported income from continuing operations and core earnings:

In millions	2006			2005			2004
REPORTED INCOME
Oil and Gas ^(a)	$	7,239		$	5,968		$	4,021
Chemical		901			607			414
Corporate and Other	(239		)	392			(390		)
Pre-tax income		7,901			6,967			4,045
Income tax expense
Federal and State		1,713			665			941
Foreign ^(a)		1,753			1,262			698
Total		3,466			1,927			1,639
Income from continuing operations	$	4,435		$	5,040		$	2,406
Worldwide effective tax rate		44%			28%			41%
CORE INCOME
Oil and Gas ^(a)	$	7,239		$	6,012		$	4,021
Chemical		901			777			414
Corporate and Other	(406		)	(405		)	(485		)
Pre-tax income		7,734			6,384			3,950
Income tax expense
Federal and State		1,632			1,390			953
Foreign ^(a)		1,753			1,262			698
Total		3,385			2,652			1,651
Core income	$	4,349		$	3,732		$	2,299
Worldwide effective tax rate		44%			42%			42%

(a)	Revenues, oil and gas pre-tax income and income tax expense include taxes owed by Occidental but paid by governmental entities on its behalf of $1.1 billion, $887 million and $525 million for the years ended December 31, 2006, 2005 and 2004, respectively.

Occidental's 2006 worldwide effective tax rate was 44 percent for both reported and core income. The lower income tax rate for reported income in 2005, compared to 2006, resulted from a $335 million 2005 tax benefit due to the reversal of tax reserves no longer required and a $619 million 2005 tax benefit resulting from a closing agreement with the IRS resolving certain foreign tax credit issues.

CONSOLIDATED RESULTS OF OPERATIONS

Selected Revenue Items

In millions	2006		2005		2004
Net sales	$	17,661	$	14,597	$	10,879
Interest, dividends and other income	$	381	$	181	$	144
Gain on disposition of assets, net	$	118	$	870	$	1

The increase in net sales in 2006, compared to 2005, reflects higher crude oil prices and oil and gas production and higher chemical prices, partially offset by lower natural gas prices.

The increase in net sales in 2005, compared to 2004, reflects higher crude oil, natural gas and chemical prices.

The increase in interest, dividends and other income in 2006, compared to 2005, is primarily due to a $108 million gain related to litigation settlements and interest income earned on a higher level of cash and cash equivalents.

The increase in interest, dividends and other income in 2005, compared to 2004, reflects higher interest income earned on a higher level of cash and cash equivalents.

Gains on disposition of assets, net in 2006, includes a gain of $90 million from the sale of 10 million shares of Lyondell stock.

Gain on disposition of assets, net in 2005 includes a gain of $726 million resulting from Valero’s acquisition of Premcor and the subsequent sale of all of the Valero shares received and a gain of $140 million on the sale of 11 million shares of Lyondell stock.

Selected Expense Items

In millions	2006		2005		2004
Cost of sales ^(a)	$	6,284	$	5,425	$	4,418
Selling, general and administrative and other operating expenses	$	1,371	$	1,324	$	936
Depreciation, depletion and amortization	$	2,042	$	1,422	$	1,251
Exploration expense	$	295	$	314	$	214
Interest and debt expense, net	$	291	$	293	$	260

(a)	Excludes depreciation, depletion and amortization of $2,011 million in 2006, $1,383 million in 2005 and $1,213 million in 2004.

Cost of sales increased in 2006, compared to 2005, due to higher oil and gas production, maintenance, workover and utility costs and higher ad valorem and export taxes.

Cost of sales increased in 2005, compared to 2004, mainly due to higher oil and gas production costs and higher energy and feedstock costs.

Selling, general and administrative and other operating expenses increased in 2006, compared to 2005, due to higher oil and gas production taxes and increases in share-based and incentive compensation expense.

Selling, general and administrative and other operating expenses increased in 2005, compared to 2004, due to the chemical plant write-offs and writedowns in 2005, higher costs in oil and gas, including higher production-related taxes, and increases in share-based compensation expense.

DD&A increased in 2006, compared to 2005, due to increased production, mainly from the Vintage acquisition and higher costs of new reserve additions resulting in a higher DD&A rate.

DD&A increased in 2005, compared to 2004, due to higher costs of new reserve additions resulting in a higher DD&A rate.

The increase in exploration expense in 2005, compared to 2004, was due mostly to higher dry hole write-offs and impairment costs and higher seismic and geological and geophysical costs.

Interest and debt expense in 2006, 2005 and 2004 included pre-tax debt repayment expenses of $35 million, $42 million and $17 million, respectively. Excluding the effects of these debt repayment charges, interest expense increased in 2005, compared to 2004, due to higher interest rates which were partially offset by lower debt levels.

Selected Other Items

In millions	2006			2005			2004
Provision for income taxes	$	3,466		$	1,927		$	1,639
Income from equity investments	$	(182	)	$	(232	)	$	(113	)
Gain on Lyondell stock issuance	$	—		$	—		$	(121	)

The increase in the provision for income taxes in 2006, compared to 2005, was due to an increase in income before taxes in 2006, a $335 million 2005 tax benefit due to the reversal of tax reserves no longer required, and a $619 million 2005 tax benefit related to the resolution of certain IRS tax issues.

The decrease in income from equity investments in 2006, compared to 2005, is mainly due to the change in Occidental’s accounting for its Lyondell shares from equity method to available-for-sale investment in May 2006.

The increase in income from equity investments in 2005, compared to 2004, was due to improved results from the Lyondell equity investment and higher income from a Russian oil and gas equity investee.

The gain on Lyondell stock issuance in 2004 represents Occidental's share of the increase in Lyondell's net equity resulting from Lyondell's issuance of stock to purchase Millennium.

CONSOLIDATED ANALYSIS OF FINANCIAL POSITION

The changes in the following components of Occidental’s balance sheet are discussed below:

Selected Balance Sheet Components

In millions	2006		2005
CURRENT ASSETS
Cash and cash equivalents	$	1,339	$	2,188
Short-term investments		240		252
Trade receivables, net		2,825		2,531
Receivables from joint ventures, partnerships and other		499		568
Inventories		825		716
Prepaid expenses and other		256		255
Assets of discontinued operations	22		427
Total current assets	$	6,006	$	6,937
Long-term receivables, net	$	231	$	377
Investments in unconsolidated entities	$	1,344	$	1,209
Property, plant and equipment, net	$	24,316	$	17,171
CURRENT LIABILITIES
Current maturities of long-term debt and capital lease liabilities	$	171	$	46
Accounts payable		2,263		2,046
Accrued liabilities		1,575		1,569
Dividends payable		188		147
Domestic and foreign income taxes		396		326
Liabilities of discontinued operations	131		138
Total current liabilities	$	4,724	$	4,272
Long-term debt, net	$	2,619	$	2,873
Deferred credits and other liabilities-income taxes	$	2,326	$	970
Deferred credits and other liabilities-other	$	2,966	$	2,621
Long-term liabilities of discontinued operations	$	195	$	—
Stockholders’ equity	$	19,184	$	15,032

Assets

See “Cash Flow Analysis” for discussion about the change in cash and cash equivalents. The increase in trade receivables is due to higher worldwide oil prices and higher oil and gas production volumes during the fourth quarter of 2006 versus 2005. The increase in inventories is due to an increase in materials and supplies, mainly in Oman and Colombia, and increases in chemical inventory volumes during the fourth quarter of 2006 versus 2005. The decrease in assets of discontinued operations is due to the write-off of the investment in Block 15 in Ecuador during the second quarter of 2006.

The decrease in long-term receivables reflects lower mark-to-market adjustments on long-term derivative financial instruments. The increase in investments in unconsolidated entities is due to mark-to-market adjustments on the Lyondell investment, which became an available-for-sale investment in May 2006 and additional capital investments made on the Dolphin Project during 2006, partially offset by the sale of 10 million shares of Lyondell common stock. The increase in PP&E is due to the acquisitions of Vintage and properties from Plains completed in the first and third quarters of 2006, respectively, and oil and gas capital expenditures during 2006.

Liabilities and Stockholders' Equity

Debt to Capitalization ^(a)

(a)	This ratio is computed by dividing year-end Total Debt, as shown in the "MD&A-Strategy-Key Performance Indicators-Debt Structure," by the sum of year-end Total Debt plus year-end Stockholders’ Equity.

The increase in current maturities of long-term debt and capital leases is due to the 4.0-percent medium-term notes, which were reclassified from long-term to current since they mature in 2007. The increase in accounts payable is due to the Vintage acquisition, higher prices and volumes for purchased oil in the marketing and trading operations, and higher chemical volume and feedstock price increases during 2006.

The decrease in long-term debt, net is due to various debt redemptions and repurchases throughout 2006, offset by the debt assumed in the Vintage acquisition. The increase in deferred credits and other liabilities – income taxes is due to the additional deferred taxes recorded as part of the Vintage acquisition purchase accounting. The increase in deferred credits and other liabilities – other is due to additional pension liabilities recorded in connection with Occidental’s adoption of Statement of Financial Accounting Standards (SFAS) 158. The increase in long-term liabilities of discontinued operations was due to accruing the OCP ship-or-pay obligations in Ecuador.

The increase in stockholders' equity reflects the stock issued as consideration for the Vintage acquisition and net income for 2006, partially offset by treasury stock repurchases and dividend payments.

LIQUIDITY AND CAPITAL RESOURCES

At December 31, 2006, Occidental had approximately $1.6 billion in cash and short-term investments on hand. Although income and cash flows are largely dependent on oil and gas prices and production, Occidental believes that cash and short-term investments on hand and cash generated from operations will be sufficient to fund its operating needs, capital expenditure requirements, dividend payments, potential acquisitions, its announced common stock repurchase program and debt repurchases. If needed, Occidental could access its existing credit facilities.

Available but unused lines of committed bank credit totaled approximately $1.5 billion at December 31, 2006. In September 2006, Occidental amended and restated its $1.5 billion bank credit (Credit Facility) to, among other things, lower the interest rate and extend the term to September 2011. The Credit Facility provides for the termination of the loan commitments and requires immediate repayment of any outstanding amounts if certain events of default occur or if Occidental files for bankruptcy. Occidental had not drawn down any amounts on the Credit Facility at December 31, 2006. None of Occidental's committed bank credits contain material adverse change (MAC) clauses or debt rating triggers that could restrict Occidental's ability to borrow under these lines. Occidental's credit facilities and debt agreements do not contain rating triggers that could terminate bank commitments or accelerate debt in the event of a ratings downgrade.

At December 31, 2006, under the most restrictive covenants of certain financing agreements, Occidental's capacity for additional unsecured borrowing was approximately $44.8 billion, and the capacity for the payment of cash dividends and other distributions on, and for acquisitions of, Occidental's capital stock was approximately $17.2 billion, assuming that such dividends, distributions and acquisitions were made without incurring additional borrowing.

In January 2006, Occidental completed the Vintage acquisition and paid $1.3 billion in cash to former Vintage shareholders and issued approximately 56 million shares of Occidental common stock, which were valued at $2.1 billion. In addition, Occidental assumed Vintage’s debt, which had an estimated fair market value of $585 million at closing.

In 2006, Occidental redeemed or repurchased $274 million of this newly acquired debt, including all of its 7.875-percent Vintage senior subordinated notes due 2011 and $74 million of its 8.25-percent Vintage senior notes due 2012. Additionally, Occidental redeemed all of its 7.375-percent senior notes due 2008 and purchased and retired a total of $120 million of its 4-percent medium-term notes due 2007, its 4.25-percent medium-term notes due 2010, its 6.75-percent senior notes due 2012, its 9.25-percent senior debentures due 2019, its 8.75-percent senior notes due 2023 and its 8.45-percent senior notes due 2029.

In 2005, Occidental redeemed all of its 5.875-percent senior notes due 2007, all of its 4.101-percent medium-term senior notes due 2007, all of its 7.65-percent senior notes due 2006 and three of its unsecured subsidiary notes due 2028 through 2030. In addition, Occidental purchased and retired a total of $213 million of its 6.75-percent senior notes due 2012, its 10.125-percent senior notes due 2009, its 4-percent medium-term senior notes due 2007 and its 4.25-percent medium-term senior notes due 2010.

In July 2005, Dolphin Energy entered into a bridge loan in an amount of $2.45 billion. The proceeds of the new bridge loan were used to pay off amounts outstanding on a previous bridge loan and are being used to fund the construction of the Dolphin Project. The new bridge loan has a term of four years, is a revolving credit facility for the first two years and may be converted to a term loan thereafter. In September 2005, Dolphin Energy entered into an agreement with banks to provide a $1.0 billion Islamic-law-compliant facility to fund the construction of a certain portion of the Dolphin Project. This four-year financing facility is structured as a transaction in which Dolphin Energy constructs part of the midstream portion of the Dolphin Project on behalf of a group of Islamic investors and enters into a lease to use such assets upon construction completion. Occidental guarantees 24.5 percent of both of these obligations of Dolphin Energy. At December 31, 2006, Occidental’s portion of the bridge loan and Islamic-law-compliant facility draw downs were $469 million and $184 million, respectively. Occidental had recorded $473 million on the balance sheet at December 31, 2006, for the combined bridge loan and Islamic-law-compliant facility. The remaining amounts of the bridge loan and Islamic-law-compliant facility draw downs are included in guarantees discussed in “Off-Balance-Sheet Arrangements – Guarantees” below.

In the first quarter of 2005, Occidental filed a shelf registration statement for up to $1.5 billion of various securities. As of December 31, 2006, no securities had been issued under this shelf.

In January 2007, Occidental completed a cash tender offer for its 10.125-percent senior debentures due 2009, 9.25-percent senior debentures due 2019, 8.75-percent senior notes due 2023, 7.2-percent senior debentures due 2028 and 8.45-percent senior notes due 2029, resulting in the repurchase of a portion of these debt instruments totaling $659 million. The repurchases were funded with Occidental’s cash on hand and resulted in debt repurchase expenses of $165 million.

Cash Flow Analysis

In millions		2006			2005			2004
Net cash provided by operating activities		$	6,353		$	5,337		$	3,878

The significant increase in operating cash flow in 2006, compared to 2005, resulted from several factors. The most important drivers were higher crude oil prices, higher oil and gas production and, to a much lesser extent, higher chemical margins, partially offset by the effects of lower gas prices and reduced cash flow from discontinued operations. In 2006, Occidental’s realized crude oil prices increased by 15 percent and its oil and gas production increased by over 14 percent compared to 2005. The increase in production was mainly due to the 11 months of production from the Vintage acquisition.

Increases in the costs of producing oil and gas, such as purchased goods and services, and higher utility costs, gas plant costs and ad valorem and export taxes, partially offset the effect of oil price increases. Other cost elements, such as labor costs and overheads, are not significant drivers of cash flow because they are mainly fixed within a narrow range over the short to intermediate term. The cost increases had a smaller effect on cash flow than the higher crude oil prices and the higher crude oil and natural gas production.

Most major chemical prices increased in 2006, compared to 2005, at a higher rate than ethylene costs, thereby improving chemical margins. The overall impact of the chemical price changes on cash flow was much less than for oil and gas price changes because the chemical segment earnings and cash flow are significantly smaller than those for the oil and gas segment. Sales volumes for certain chemical products were slightly lower in 2006, however, this did not have a significant effect on Occidental’s earnings and cash flow.

The significant increase in operating cash flow in 2005, compared to 2004, resulted from several factors. The most important drivers were the significantly higher oil and natural gas prices and, to a much lesser extent, chemical prices. Although the changes in realized prices varied among the regions in which Occidental operates, in 2005, Occidental's realized oil prices were higher overall by 37 percent. Occidental’s realized natural gas price increased over 33 percent in the United States, where approximately 80 percent of Occidental’s natural gas was produced in 2005.

Increases in the costs of producing oil and gas, such as purchased goods and services, and higher utility, gas plant and production taxes, partially offset oil and gas sales price increases, but such cost increases had a much lower effect on cash flow than the realized price increases. Other cost elements, such as labor costs and overheads, are not significant drivers of cash flow because they are mainly fixed within a narrow range over the short to intermediate term.

Most major chemical prices increased in 2005 at a higher rate than the energy-driven increase in feedstock and power costs, thereby improving profits and cash flow. The overall impact of the chemical price changes on cash flow was much less than for oil and gas price changes, not only because the chemical segment earnings and cash flow are significantly smaller than those for the oil and gas segment, but also because of increases in energy price-driven feedstock and electric power costs, which are major elements of manufacturing cost for the chemical segment's products. Sales volumes for chemical products generally were higher in 2005, but this did not have a significant effect on Occidental's earnings and cash flow.

Other non-cash charges to income in 2006 included stock incentive plan amortization, deferred compensation and environmental remediation accruals. Other non-cash charges to income in 2005 included chemical asset write-downs, deferred compensation, stock incentive plan amortization and environmental remediation accruals. Other non-cash charges in 2004 included deferred compensation, stock incentive plan amortization, environmental remediation accruals and a chemical asset write-down.

In millions		2006			2005			2004
Net cash used by investing activities		$	(4,383	)	$	(3,161	)	$	(2,428	)

The 2006 amount includes the cash payments associated with the acquisition of Vintage and the property acquisition from Plains, partially offset by cash proceeds from the Vintage assets subsequently sold and from the sale of Lyondell shares.

The 2005 amount includes the cash payments for several Permian Basin acquisitions, the acquisition of the Vulcan chlor-alkali manufacturing facilities and the payments to re-enter Libya and to assume operations of the Mukhaizna field in Oman. These were partially offset by the cash proceeds from the sale of the Premcor-Valero shares and the Lyondell shares.

The 2004 amount includes the purchase of a pipeline and gathering system in the Permian Basin and a $204 million advance to the Elk Hills Power LLC (EHP) equity investment, which EHP used to repay a portion of its debt.

Also, see the "Capital Expenditures" section below.

In millions		2006			2005			2004
Net cash used by financing activities		$	(2,819	)	$	(1,187	)	$	(821	)

The 2006 amount consists of $1.5 billion of cash paid for Occidental’s stock repurchase plan and net debt payments of approximately $900 million.

The 2005 amount includes net debt payments of approximately $900 million.

The 2004 amount includes $466 million paid to redeem the trust preferred securities in January 2004 and $159 million paid to redeem Occidental's 6.5-percent senior notes.

Occidental paid common stock dividends of $646 million in 2006, $483 million in 2005 and $424 million in 2004.

Capital Expenditures

In millions	2006		2005		2004
Oil and Gas	$	2,721	$	2,137	$	1,526
Chemical		251		173		155
Corporate and Other	33		14		39
Total ^(a)	$	3,005	$	2,324	$	1,720

(a)	Excludes acquisitions. Amounts are included in net cash used by investing activities discussed above.

Occidental’s capital spending estimate for 2007 is approximately $3.3 to $3.4 billion. Most of the capital spending will be allocated to oil and gas exploration, production and development activities for the Oman Mukhaizna project, the Vintage properties in Argentina and California, Libya, Qatar, the Permian Basin and Elk Hills.

Commitments at December 31, 2006, for major capital expenditures during 2007 and thereafter were approximately $787 million. Occidental will fund these commitments and capital expenditures with cash from operations.

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 GAAP 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 "Oil and Gas Segment — Business Review — Middle East/North Africa — Dolphin Project" and "Liquidity and Capital Resources" for further information.

Ecuador

In Ecuador, Occidental has a 14-percent interest in the OCP oil export pipeline. As of December 31, 2006, Occidental’s net investment in and advances to the project totaled $72 million. Occidental reports this investment in its consolidated financial 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. In May 2006, Ecuador terminated Occidental’s contract for the operation of Block 15, which comprised all of its oil-producing operations in the country, and seized Occidental’s Block 15 assets. Occidental’s guarantee of its share of the ship-or-pay obligations provides the lenders the right to require Occidental to make an advance tariff payment as a result of the expropriation. At December 31, 2006, the total pre-tax advance tariff payment of approximately $95 million was accrued in Occidental’s consolidated financial statements, and was included in the net after-tax charge of $296 million discussed in the “Business Review – Latin America – Ecuador” section. This advance tariff would be used by the pipeline company to service or prepay project debt. At December 31, 2006, Occidental also had obligations relating to performance bonds totaling $14 million.

Leases

Occidental has entered into various operating-lease agreements, mainly for railcars, power plants, manufacturing facilities and office space. Occidental leases assets when it offers greater operating flexibility. Lease payments are expensed mainly as cost of sales. See the Contractual Obligations table below.

Guarantees

Occidental has entered into various guarantees including performance bonds, letters of credit, indemnities, commitments and other forms of guarantees provided by Occidental to third parties, mainly to provide assurance that OPC or its subsidiaries and affiliates will meet their various obligations (guarantees).

At December 31, 2006, the notional amount of the guarantees that are subject to the reporting requirements of Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 45 was approximately $270 million, which consists of Occidental’s guarantee of equity investees’ debt, primarily from the Dolphin Project equity investment, and other commitments.

Contractual Obligations

The table below summarizes and cross-references certain contractual obligations that are reflected in the Consolidated Balance Sheets as of December 31, 2006 and/or disclosed in the accompanying Notes.

			Payments Due by Year
Contractual Obligations (in millions)	Total		2007		2008 to 2009		2010 to 2011		2012 and thereafter
Consolidated Balance Sheet
Long-term debt (Note 5) ^(a)	$	2,774	$	171	$	705	$	307	$	1,591
Capital leases (Note 6)		38		1		2		2		33
Other liabilities ^(b)		5,353		3,754		620		347		632
Other Obligations
Operating leases (Note 6) ^(c)		1,418		175		271		187		785
Purchase obligations ^{(d, e)}		6,637		1,660		1,969		1,613		1,395
Total	$	16,220	$	5,761	$	3,567	$	2,456	$	4,436

(a)	Excludes unamortized debt premiums and interest expense on the debt. As of December 31, 2006, interest on long-term debt totaling $1.8 billion is payable in the following years: 2007 - $174 million, 2008 to 2009 - $317 million, 2010 to 2011 - $258 million and 2012 and thereafter - $1,053 million. In January 2007, Occidental completed a cash tender offer and repurchased $659 million of long-term debt included in the table, which will reduce future interest payments by approximately $880 million over the original maturities of the repurchased debt.
(b)	Includes accounts payable, certain accrued liabilities and obligations under postretirement benefit and deferred compensation plans.
(c)	Amounts have not been reduced for sublease rental income.
(d)	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 7-percent discount rate.
(e)	Amounts exclude purchase obligations related to oil and gas marketing and trading activities where an offsetting sales position exists.

LAWSUITS, CLAIMS, COMMITMENTS, CONTINGENCIES AND RELATED MATTERS

OPC or certain of its subsidiaries have been named in many 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 or certain of its subsidiaries also have been named in proceedings under the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA) and similar federal, state, local and foreign 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.

Since 2004, Occidental Chemical Corporation (OCC) has been served with ten lawsuits filed in Nicaragua by approximately 2,600 individual plaintiffs. These individuals allege that they have sustained several billion dollars of personal injury damages as a result of their alleged exposure to a pesticide. OCC is aware of, but has not been served in, 24 additional cases in Nicaragua, which Occidental understands make similar allegations. In the opinion of management, the claims against OCC are without merit because, among other things, OCC believes that none of the pesticide it manufactured was ever sold or used in Nicaragua. Under the applicable Nicaraguan statute, defendants are required to pay pre-trial deposits so large as to effectively prohibit defendants from participating fully in their defense. OCC filed a response to the complaints contesting jurisdiction without posting such pre-trial deposit. In 2004, the judge in one of the cases (Osorio Case), ruled the court had jurisdiction over the defendants, including OCC, and that the plaintiffs had waived the requirement of the pre-trial deposit. In order to preserve its jurisdictional defense, OCC elected not to make a substantive appearance in the Osorio Case. In 2005, the judge in the Osorio Case entered judgment against several defendants, including OCC, for damages totaling approximately $97 million. In December 2006, the court in a second case in Nicaragua (Rios Case) entered a judgment against several defendants, including OCC, for damages totaling approximately $800 million. While preserving its jurisdictional defenses, OCC has appealed the judgments in the Osorio and Rios Cases. OCC has no assets in Nicaragua and, in the opinion of management, any judgment rendered under the statute, including in the Osorio and Rios Cases, would be unenforceable in the United States.

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 2001 are generally closed for U.S. federal corporate income tax purposes. Corporate tax returns for taxable years 2001 through 2003 are in various stages of audit by the U.S. Internal Revenue Service. Disputes may 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, 2006, 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 $16 million, which was payable as follows (in millions): 2007 – $12 and 2008 – $4. Fixed payments under these agreements were $18 million in 2006, $17 million in 2005 and $19 million in 2004. See "Off-Balance-Sheet Arrangements — Contractual Obligations" for further information.

Occidental has certain other commitments under contracts, guarantees and joint ventures, including purchase commitments for goods and services at market-related prices and certain other contingent liabilities. See "Off-Balance-Sheet Arrangements" for further information. Some of these commitments,

although not fixed or determinable, involve capital expenditures and are part of the $3.3 to $3.4 billion in capital expenditures estimated for 2007.

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, 2006, Occidental is not aware of circumstances that it believes would reasonably be expected to lead to future indemnity claims against it in connection with these transactions that would result in payments materially in excess of reserves.

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 or the timing of these liabilities. 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 are subject to stringent federal, state, local and foreign laws and regulations relating to improving or maintaining environmental quality. Costs associated with environmental compliance have increased over time and are expected to rise in the future. Environmental expenditures related to current operations are factored into the overall business planning process and are 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 of substances to the environment. 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 domestic and foreign remediation sites, including currently owned facilities and previously owned sites. Also, OPC or 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., which reports its results directly to Occidental’s corporate management.

The following table presents Occidental’s environmental remediation reserves at December 31, 2006, 2005 and 2004, grouped by three categories of environmental remediation sites:

$ amounts in millions	2006			2005			2004
	# of Sites	Reserve Balance		# of Sites	Reserve Balance		# of Sites	Reserve Balance
CERCLA & equivalent sites	105	$	226	128	$	236	125	$	239
Active facilities	21		116	18		114	16		75
Closed or sold facilities	40	70		39	68		39	61
Total	166	$	412	185	$	418	180	$	375

The following table shows environmental reserve activity for the past three years:

In millions	2006			2005			2004
Balance - Beginning of Year	$	418		$	375		$	372
Remediation expense and interest accretion		48			63			60
Changes from acquisitions		17			45			6
Payments		(71	)		(71	)		(63	)
Other	—			6			—
Balance - End of Year	$	412		$	418		$	375

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 believes it is reasonably possible that it will continue to incur additional liabilities beyond those recorded for environmental remediation at these sites. The range of reasonably possible loss for existing environmental remediation matters could be up to $430 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

As of December 31, 2006, OPC or certain of its subsidiaries have been named in 105 CERCLA or state equivalent proceedings, as shown below.

Description ($ amounts in millions)	# of Sites	Reserve Balance
Minimal/No exposure ^(a)	85	$	6
Reserves between $1-10 MM	14		55
Reserves over $10 MM	6		165
Total	105	$	226

(a)

Includes 32 sites for which Maxus Energy Corporation has retained the liability and indemnified Occidental, 5 sites where Occidental has denied liability without challenge, 15 sites where Occidental’s reserves are less than $50,000 each, and 33 sites where reserves are between $50,000 and $1 million each.

The six sites with individual reserves over $10 million in 2006 include a former copper mining and smelting operation in Tennessee, two closed landfills in western New York and groundwater treatment facilities at three closed chemical plants (Montague, Michigan, western New York and Tacoma, Washington).

Active Facilities

Certain subsidiaries of OPC are currently addressing releases of substances from past operations at 21 active facilities. Five facilities — a chemical plant in Louisiana, a phosphorus recovery operation in Tennessee, a chemical plant in Texas, a chemical plant in Kansas and certain oil and gas properties in the southwestern United States — account for 69 percent of the reserves associated with these facilities.

Closed or Sold Facilities

There are 40 sites formerly owned or operated by certain subsidiaries of OPC that have ongoing environmental remediation requirements in which OPC or its subsidiaries are involved. Five sites account for 70 percent of the reserves associated with this group. The five 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, a closed OCC chemical plant in Pennsylvania, a closed landfill in western New York and a water treatment facility at a former OCC chemical plant in North Carolina.

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	2006		2005		2004
Operating Expenses
Oil and Gas	$	95	$	65	$	51
Chemical	73		67		59
	$	168	$	132	$	110
Capital Expenditures
Oil and Gas	$	55	$	43	$	44
Chemical	25		21		12
	$	80	$	64	$	56
Remediation Expenses
Corporate	$	47	$	62	$	59

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.

Occidental presently estimates that capital expenditures for environmental compliance will be approximately $94 million for 2007 and $100 million for 2008.

FOREIGN INVESTMENTS

Portions of Occidental’s assets are located outside of North America. Occidental conducts its financial affairs so as to mitigate its exposure against risks associated with the locations of these assets. At December 31, 2006, the carrying value of Occidental’s assets in countries outside North America aggregated approximately $9.2 billion, or approximately 28 percent of Occidental’s total assets at that date. Of such assets, approximately $5.0 billion are located in the Middle East/North Africa, approximately $3.9 billion are located in Latin America, and substantially all of the remainder are located in the Other Eastern Hemisphere region. For the year ended December 31, 2006, net sales outside North America totaled $5.6 billion, or approximately 31 percent of total net sales.

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. The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if a determination is made that proved reserves have been found. If no proved reserves have been found, the costs of each of the related exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. Occidental's practice is to expense the costs of such exploratory wells if a determination of proved reserves has not been made within a twelve-month period after drilling is complete. Occidental has no proved oil and gas reserves for which the determination of commercial viability is subject to the completion of major additional capital expenditures.

Annual lease rentals and geological, geophysical and seismic 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.

Several factors could change Occidental’s recorded oil and gas reserves. Occidental receives a share of production from PSCs to recover its costs and an additional share for profit. Occidental’s share of production and reserves 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. 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 changes 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 estimated when the reserves were initially recorded. Occidental’s revisions to proved reserves were positive for 2006 and amounted to less than 1 percent of the total reserves for the year. In 2005, revisions to proved reserves were negative and amounted to less than 1 percent of the total reserves for the year. In 2004, revisions to proved reserves were positive and amounted to approximately 2 percent of the total reserves. 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 SFAS No. 144 impairments of oil and gas assets over the past three years.

If Occidental’s consolidated oil and gas reserves were to change based on the factors mentioned above, the most significant impact would be on the DD&A rate. For example, a 5-percent increase in the amount of consolidated oil and gas reserves would change the rate from $8.35 per barrel to $7.94 per barrel, which would increase pre-tax income by $88 million annually. A 5-percent decrease in the oil and gas reserves would change the rate from $8.35 per barrel to $8.77 per barrel and would result in a decrease in pre-tax income of $88 million annually.

DD&A of oil and gas producing properties is determined by the unit-of-production method and could change with revisions to estimated proved reserves. The change in the DD&A rate over the past three years due to revisions of previous proved reserve estimates has been immaterial.

A portion of the carrying value of Occidental’s oil and gas properties is attributable to unproved properties. At December 31, 2006, the capitalized costs attributable to unproved properties, net of accumulated valuation allowance, were $1.7 billion. The acquisition of Vintage resulted in an addition of $1.3 billion of unproved properties in 2006. No goodwill was recorded on this transaction. During 2006, approximately $300 million of the unproved property amount was moved to proved properties. The unproved amounts are not subject to DD&A or impairment until a determination is made as to the existence of proven reserves. As exploration and development work progresses, if 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 Assets

The most critical accounting policy affecting Occidental’s chemical assets is the determination of the estimated useful lives of its PP&E. 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 ensure productive capacity is sustained. 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 sustained higher or lower product prices, which are particularly affected by both domestic and foreign competition, feedstock costs, energy prices, environmental regulations and technological changes. Over the prior three years, the change in the depreciation rate due to changes in estimated useful lives has been immaterial.

Occidental performs 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. Occidental compares 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, regulations and remaining estimated useful life. Impaired assets are written down to their estimated fair values.

Subsequent to the purchase of the Vulcan chemical assets, Occidental reviewed all of its chemical assets and decided to close its least competitive plants and upgrade the remaining operations. As a result of this review, Occidental recorded a $139 million pre-tax charge for the write-off of two previously idled chemical plants and one operating plant and a pre-tax additional charge of $20 million for the write-down of another chemical plant in 2005.

Occidental's net PP&E for chemicals is approximately $2.6 billion and its depreciation expense for 2007 is expected to be approximately $256 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 one year would increase depreciation and reduce pre-tax earnings by approximately $17 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. 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. Recoveries and reimbursements are recorded in income when receipt is probable. As of December 31, 2006 and 2005, Occidental has not accrued any reimbursements or indemnification recoveries for environmental remediation matters as assets.

Many factors could result in changes to Occidental’s environmental reserves and reasonably possible range of loss. The most significant are:

Ø	The original cost estimate may have been inaccurate.
Ø	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.
Ø	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.
Ø	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:

Ø	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.
Ø	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 bioremediation, could significantly affect remediation costs.
Ø	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 nonperforming 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 $41 million. If the reserve balance were to increase by 10 percent, Occidental would record an additional remediation expense of $41 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 ongoing 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 accounting principles.

SFAS No. 158

In September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans—an amendment of FASB Statements No. 87, 88, 106, and 132(R).” This statement requires an employer to recognize the overfunded or underfunded amounts of its defined benefit pension and postretirement plans as an asset or liability and recognize changes in the funded status of these plans in the year in which the changes occur through other comprehensive income (OCI), if they are not recognized in the income statement. The statement also requires a company to use the date of its fiscal year-end to measure the plans. The recognition and disclosure provisions of SFAS No. 158 are effective for fiscal years ending after December 15, 2006. The requirement to use the fiscal year-end as the measurement date is effective for fiscal years ending after December 15, 2008. Occidental adopted this statement on December 31, 2006, and recorded an additional liability of $233 million and a reduction of accumulated OCI, deferred tax liabilities, other assets and minority interest of $168 million, $104 million, $42 million and $3 million, respectively.

SAB 108

In September 2006, the SEC issued Staff Accounting Bulletin (SAB) 108, “Financial Statements – Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements.” SAB 108 requires quantification of the impact of all prior year misstatements from both an income statement and a balance sheet perspective to determine if the misstatements are material. SAB 108 is effective for financial statements issued for fiscal years ending after November 15, 2006. Occidental adopted SAB 108 effective December 31, 2006 and there was no material effect on the financial statements upon adoption.

FIN 48

In June 2006, the FASB issued FIN 48, “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109.” This interpretation specifies that benefits from tax positions should be recognized in the financial statements only when it is more-likely-than-not that the tax position will be sustained upon examination by the appropriate taxing authority having full knowledge of all relevant information. A tax position meeting the more-likely-than-not recognition threshold should be measured at the largest amount of benefit for which the likelihood of realization upon ultimate settlement exceeds 50 percent. It also requires additional disclosures related to these tax positions. FIN 48 is effective for fiscal years beginning after December 15, 2006. Occidental will adopt FIN 48 in the first quarter of 2007 and expects there will not be a material effect on the financial statements upon adoption.

SFAS No. 157

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” This statement establishes a framework for measuring fair value and expands disclosures about fair value measurements. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007. Occidental is currently assessing the effect of SFAS No. 157 on its financial statements.

FSP AUG AIR-1

In September 2006, the FASB issued FASB Staff Position (FSP) AUG AIR-1, “Accounting for Planned Major Maintenance Activities.” This FSP prohibits the use of the accrue-in-advance method of accounting for planned major maintenance activities in annual and interim financial reporting periods. FSP AUG AIR-1 is effective for the first fiscal year beginning after December 15, 2006. Occidental will adopt FSP AUG AIR-1 in the first quarter of 2007 and expects there will not be a material effect on the financial statements upon adoption.

EITF Issue No. 06-4

In September 2006, the Emerging Issues Task Force (EITF) finalized the provisions of EITF Issue No. 06-4, “Accounting for Deferred Compensation and Postretirement Benefit Aspects of Endorsement Split-Dollar Life Insurance Arrangements”. This EITF Issue provides accounting guidance for endorsement split-dollar life insurance arrangements and require employers to recognize liability for future benefits in accordance with SFAS 106 or Accounting Principles Board (APB) Opinion No. 12. The recognition and disclosure provisions of EITF Issue No. 06-4 are effective for fiscal years ending after December 15, 2007. Occidental is currently assessing the effect of this EITF Issue on its financial statements.

EITF Issue No. 06-5

In September 2006, the EITF finalized the provisions of EITF Issue No. 06-5, “Accounting for Purchase of Life Insurance-Determining the Amount That Could Be Realized in Accordance with FASB Technical bulletin No. 85-4.” This EITF Issue provides accounting guidance for

life insurance policies and requires employers to consider and account for any additional amounts or restrictions under the terms of such policies. The recognition and disclosure provisions of EITF Issue No. 06-5 are effective for fiscal years beginning after December 15, 2006. Occidental will adopt this EITF Issue in the first quarter of 2007 and expects there will not be a material effect on the financial statements upon adoption.

SFAS No. 123(R)

On July 1, 2005, Occidental early adopted the fair value recognition provisions of SFAS No. 123(R), "Share-Based Payments", under the modified prospective transition method. Since most of Occidental’s existing stock-based compensation was already being recorded in the income statement, Occidental decided to early adopt SFAS 123(R) so that the remaining awards would be accounted for in a similar manner. Prior to July 1, 2005, Occidental applied the APB Opinion No. 25 intrinsic value accounting method for its stock incentive plans. Under the modified prospective transition method, the fair value recognition provisions apply only to new awards or awards modified after July 1, 2005. Additionally, the fair value of existing unvested awards at the date of adoption is recorded in compensation expense over the remaining requisite service period. Results from prior periods have not been restated. As a result of adopting this statement in the third quarter of 2005, Occidental recorded a $3 million after-tax credit as a cumulative effect of a change in accounting principles.

EITF Issue No. 04-13

In September 2005, the EITF finalized the provisions of EITF Issue No. 04-13, "Accounting for Purchases and Sales of Inventory with the Same Counterparty", which provides accounting guidance about whether buy/sell arrangements should be accounted for at historical cost and whether these arrangements should be reported on a gross or net basis. Buy/sell arrangements typically are contractual arrangements where the buy and sell agreements are entered into in contemplation of one another with the same counterparty. Occidental reports all buy/sell arrangements on a net basis and at historical cost. This Issue was effective in the first interim period beginning after March 15, 2006. Occidental prospectively adopted this Issue in the second quarter of 2006 and there was no material effect on the financial statements upon adoption.

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 has entered into derivative instrument transactions to reduce these price and rate fluctuations. A derivative is an instrument that, among other characteristics, derives its value from changes in 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.

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 an estimated annual effect on pre-tax income of approximately $150 million. If natural gas prices vary by $0.25 per Mcf, it would have an estimated annual effect on pre-tax income of approximately $51 million. 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; however, changes in cost usually offset part of the effect of price changes on margins. If chlorine and caustic soda prices vary by $10/ton, it would have approximately a $15 million and $30 million pre-tax annual effect on income, respectively. If PVC prices vary by $.01/lb, it would have approximately a $25 million pre-tax annual effect on income. If ethylene dichloride (EDC) prices vary by $10/ton, it would have approximately a $5 million pre-tax annual effect on income. 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 2006 average contract prices were: chlorine—$318/ton, caustic soda—$338/ton, PVC—$0.55/lb and EDC—$310/ton.

Marketing and Trading Operations

Occidental periodically uses different types of derivative instruments to achieve the best prices for oil and gas. Derivatives have been used by Occidental to reduce its exposure to price volatility and to 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. Occidental's use of derivatives in marketing and trading activities relates primarily to managing cash flows from third-party purchases, which includes Occidental’s periodic gas storage activities.

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 Control Policy. The Chief Financial Officer and the 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 value at risk, limits on credit, limits on trading, segregation of duties, delegation of authority and a number of other policy and procedural controls.

Fair Value of Marketing and Trading Derivative Contracts

The following tables reconcile the changes in the net fair value of Occidental’s marketing and trading contracts, a portion of which are hedges, during 2006 and 2005 and segregate the open contracts at December 31, 2006 by maturity periods.

In millions	2006			2005
Fair value of contracts outstanding at beginning of year – unrealized (losses) gains	$	(457	)	$	30
Losses on changes for contracts realized or otherwise settled during the year		106			56
Changes in fair value attributable to changes in valuation techniques and assumptions		—			—
Losses or other changes in fair value	(4		)	(543		)^(a)
Fair value of contracts outstanding at end of year – unrealized losses	$	(355	)	$	(457	)

(a)	Primarily relates to production hedges.

	Maturity Periods
Source of Fair Value – unrealized (losses) gains	2007			2008 to 2009			2010 to 2011			2012 and thereafter			Total Fair Value
Prices actively quoted	$	(43	)	$	6		$	2		$	2		$	(33	)
Prices provided by other external sources		62			18			3			(1	)		82
Prices based on models and other valuation methods ^(a)		(63	)		(187	)		(154	)		—			(404	)
Total	$	(44	)	$	(163	)	$	(149	)	$	1		$	(355	)

(a)

The underlying prices utilized for the 2007 through 2011 fair value calculations of the options are based on monthly NYMEX published prices. The underlying prices for years 2012 and thereafter are based on the year-end NYMEX published prices, as published monthly prices are not available. These prices are entered into an industry standard options pricing model to determine fair value.

Production Hedges

In 2005, Occidental entered into a series of fixed price swaps and costless collar agreements that qualify as cash-flow hedges for the sale of a portion of its crude oil production. Additionally, Occidental acquired oil and gas fixed price and basis swaps with the Vintage acquisition. These hedges continue to the end of 2011. The 2006 volume that was hedged was less than 4 percent of Occidental’s 2006 crude oil and natural gas production. Information about these cash-flow hedges, which are included in the total fair value of ($355) million in the table above, is presented in a tabular presentation below as of December 31, 2006 (volumes in thousands of barrels):

	Crude Oil
	Fixed Price Swaps		Costless Collars
	Daily Volume	Average Price	Daily Volume	Average Floor	Average Cap
2007	9	$39.67	7	$40.43	$45.21
2008	—	—	14	$34.07	$47.47
2009	—	—	13	$33.15	$47.41
2010	—	—	12	$33.00	$46.35
2011	—	—	12	$32.92	$46.27

	Natural Gas Swaps
	Fixed Price		Basis
(MMBTU/Day) ^(a)	Daily Volume	Average Price	Daily Volume	Average Price
2007	2,500	$6.00	2,500	$0.03

(a)	One MMBTU is one million British thermal units, which equals approximately 1 MCF.

	Crude Oil		Natural Gas Swaps
($ millions)	Fixed Price Swaps	Costless Collars	Fixed Price	Basis	Total
Fair value liability	($81)	($392)	($1)	($1)	($475)

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 marketing and trading activities. This method determines the maximum potential negative short-term change in fair value with a 95-percent level of confidence. The marketing and trading value at risk was immaterial during all of 2006.

Interest Rate Risk
General

Occidental's exposure to changes in interest rates relates primarily to its long-term debt obligations. In 2005, Occidental terminated all of its interest-rate swaps that were accounted for as fair-value hedges. These hedges had effectively converted approximately $1.7 billion of fixed-rate debt to variable-rate debt. The fair value of the swaps at termination resulted in a gain of approximately $20 million, which was recorded into income when the debt was paid in 2005 and 2006. The amount of interest expense recorded in the income statement was lower, as a result of the swaps and recognition of the gain, by approximately $13 million, $21 million and $56 million for the years ended December 31, 2006, 2005 and 2004, respectively.

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 unamortized loss on the hedges at December 31, 2006 was approximately $18 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.

Tabular Presentation of Interest Rate Risk
In millions of U.S. dollars, except rates

The table below provides information about Occidental's debt obligations which are sensitive to changes in interest rates. Debt amounts represent principal payments by maturity date.

Year of Maturity	U.S. Dollar Fixed-Rate Debt		U.S. Dollar Variable-Rate Debt		Grand Total ^(a)
2007	$	171	$	—	$	171
2008		10		—		10
2009		222		473		695
2010		239		—		239
2011		—		68		68
2012		644		—		644
Thereafter		901		46		947
Total	$	2,187	$	587	$	2,774
Average interest rate		7.54%		5.25%		7.06%
Fair Value	$	2,497	$	587	$	3,084

(a)	Excludes unamortized net premiums of $16 million.

Credit Risk

Occidental’s energy contracts are spread among several 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. Credit exposure for each customer is monitored for outstanding balances, current month activity, and forward mark-to-market exposure. Losses associated with credit risk have been immaterial for all years presented.

Foreign Currency Risk

A few of Occidental’s foreign operations have currency risk. Occidental manages its exposure primarily by balancing monetary assets and liabilities and maintaining cash positions only at levels necessary for operating purposes. Most international crude oil sales are denominated in U.S. dollars. Additionally, all of Occidental’s consolidated foreign oil and gas subsidiaries have the U.S. dollar as the functional currency. At December 31, 2006 and 2005, Occidental had not entered into any foreign currency derivative instruments. The effect of exchange-rate transactions in foreign currencies is included in periodic income and is immaterial.

SAFE HARBOR DISCUSSION 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 captions "Strategy," "Oil and Gas Segment — Industry Outlook," and "Chemical Segment — Industry Outlook," contain forward-looking statements and involve risks and uncertainties that could materially affect expected results of operations, liquidity, cash flows and business prospects. Words such as "estimate," "project," "predict," "will," "anticipate," "plan," "intend," "believe," "expect" or similar expressions that convey the uncertainty of future events or outcomes generally identify forward-looking statements. You should not place undue reliance on these forward-looking statements, which speak only as of the date of this report. Unless legally required, Occidental does not undertake any obligation to update any forward-looking statements as a result of new information, future events or otherwise. Certain of the risks that may affect Occidental’s results of operations and financial position appear in Part I, Item 1A "Risk Factors."

ITEM 8 FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

MANAGEMENT'S ANNUAL ASSESSMENT OF AND REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of Occidental Petroleum Corporation (Occidental) is responsible for establishing and maintaining adequate internal control over financial reporting. Occidental’s system of internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements for external purposes in accordance with generally accepted accounting principles. Occidental’s internal control over financial reporting includes those policies and procedures that: (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of Occidental’s assets; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that Occidental’s receipts and expenditures are being made only in accordance with authorizations of Occidental’s management and directors; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of Occidental’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management has assessed the effectiveness of Occidental’s internal control system as of December 31, 2006 based on the criteria for effective internal control over financial reporting described in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this assessment, management believes that, as of December 31, 2006, Occidental’s system of internal control over financial reporting is effective.

Occidental’s independent auditors, KPMG LLP, have issued an attestation report on management’s assessment of Occidental’s internal control over financial reporting.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM ON CONSOLIDATED FINANCIAL STATEMENTS

To the Board of Directors and Stockholders
Occidental Petroleum Corporation:

We have audited the accompanying consolidated balance sheets of Occidental Petroleum Corporation and subsidiaries (the Company) as of December 31, 2006 and 2005, and the related consolidated statements of income, stockholders’ equity, comprehensive income and cash flows for each of the years in the three-year period ended December 31, 2006. 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 the standards of the Public Company Accounting Oversight Board (United States). 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 subsidiaries as of December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2006, in conformity with U.S. generally accepted accounting principles. 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 3 to the consolidated financial statements, effective December 31, 2006, the Company changed its method of accounting for defined benefit pension and other postretirement plans. Effective July 1, 2005, the Company changed its method of accounting for share-based payments.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Occidental Petroleum Corporation’s internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 27, 2007 expressed an unqualified opinion on management’s assessment of, and the effective operation of, internal control over financial reporting

Los Angeles, California
February 27, 2007

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM ON INTERNAL CONTROL OVER FINANCIAL REPORTING

To the Board of Directors and Stockholders
Occidental Petroleum Corporation:

We have audited management's assessment, included in the accompanying Management’s Annual Assessment of and Report on Occidental’s Internal Control Over Financial Reporting, that Occidental Petroleum Corporation and its subsidiaries (the Company) maintained effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management's assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

In our opinion, management's assessment that the Company maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Occidental Petroleum Corporation and subsidiaries as of December 31, 2006 and 2005 and the related consolidated statements of income, stockholders’ equity, comprehensive income and cash flows for each of the years in the three-year period ended December 31, 2006 and our report dated February 27, 2007 expressed an unqualified opinion on those consolidated financial statements.

Los Angeles, California
February 27, 2007

Consolidated Statements of Income
In millions, except per-share amounts

Occidental Petroleum Corporation
and Subsidiaries

For the years ended December 31,	2006			2005			2004
REVENUES
Net sales	$	17,661		$	14,597		$	10,879
Interest, dividends and other income		381			181			144
Gains on disposition of assets, net		118			870			1
		18,160			15,648			11,024
COSTS AND OTHER DEDUCTIONS
Cost of sales (excludes depreciation, depletion and amortization of $2,011 in 2006, $1,383 in 2005 and $1,213 in 2004)		6,284			5,425			4,418
Selling, general and administrative and other operating expenses		1,371			1,324			936
Total depreciation, depletion and amortization		2,042			1,422			1,251
Environmental remediation		47			62			59
Exploration expense		295			314			214
Interest and debt expense, net		291			293			260
		10,330			8,840			7,138
INCOME BEFORE TAXES AND OTHER ITEMS		7,830			6,808			3,886
Provision for domestic and foreign income and other taxes		3,466			1,927			1,639
Minority interest		111			73			75
Income from equity investments		(182	)		(232	)		(113	)
Gain on Lyondell stock issuance		—			—			(121	)
INCOME FROM CONTINUING OPERATIONS		4,435			5,040			2,406
Discontinued operations, net		(253	)		238			162
Cumulative effect of changes in accounting principles, net		—			3			—
NET INCOME	$	4,182		$	5,281		$	2,568
BASIC EARNINGS PER COMMON SHARE
Income from continuing operations	$	5.20		$	6.25		$	3.04
Discontinued operations, net		(0.30	)		0.30			0.20
BASIC EARNINGS PER COMMON SHARE	$	4.90		$	6.55		$	3.24
DILUTED EARNINGS PER COMMON SHARE
Income from continuing operations	$	5.15		$	6.16		$	3.00
Discontinued operations, net		(0.29	)		0.29			0.20
DILUTED EARNINGS PER COMMON SHARE	$	4.86		$	6.45		$	3.20
DIVIDENDS PER COMMON SHARE	$	0.80		$	0.645		$	0.55
The accompanying notes are an integral part of these consolidated financial statements.

Consolidated Balance Sheets
In millions

Occidental Petroleum Corporation
and Subsidiaries

Assets at December 31,	2006			2005
CURRENT ASSETS
Cash and cash equivalents	$	1,339		$	2,188
Short-term investments		240			252
Trade receivables, net of reserves of $15 in 2006 and $27 in 2005		2,825			2,531
Receivables from joint ventures, partnerships and other		499			568
Inventories		825			716
Prepaid expenses and other		256			255
Assets of discontinued operations		22			427
Total current assets		6,006			6,937
LONG-TERM RECEIVABLES, NET		231			377
INVESTMENTS IN UNCONSOLIDATED ENTITIES		1,344			1,209
PROPERTY, PLANT AND EQUIPMENT
Oil and gas segment, successful efforts method		30,307			21,598
Chemical segment		5,070			4,869
Corporate and other		730			478
		36,107			26,945
Accumulated depreciation, depletion and amortization		(11,791	)		(9,774	)
		24,316			17,171
OTHER ASSETS		458			414
	$	32,355		$	26,108
The accompanying notes are an integral part of these consolidated financial statements.

Consolidated Balance Sheets
In millions, except share and per-share amounts

Occidental Petroleum Corporation
and Subsidiaries

Liabilities and Stockholders’ Equity at December 31,	2006			2005
CURRENT LIABILITIES
Current maturities of long-term debt and capital lease liabilities	$	171		$	46
Accounts payable		2,263			2,046
Accrued liabilities		1,575			1,569
Dividends payable		188			147
Domestic and foreign income taxes		396			326
Liabilities of discontinued operations		131			138
Total current liabilities		4,724			4,272
LONG-TERM DEBT, NET OF CURRENT MATURITIES AND UNAMORTIZED NET PREMIUM		2,619			2,873
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred and other domestic and foreign income taxes		2,326			970
Long-term liabilities of discontinued operations		195			—
Other		2,966			2,621
		5,487			3,591
CONTINGENT LIABILITIES AND COMMITMENTS
MINORITY INTEREST		341			340
STOCKHOLDERS' EQUITY
Common stock, $.20 par value; authorized 1.1 billion shares; outstanding shares: 2006 — 870,678,608 and 2005 — 804,430,050		174			161
Treasury stock: 2006 — 30,760,490 shares and 2005 — 193,562 shares		(1,481	)		(8	)
Additional paid-in capital		6,905			4,827
Retained earnings		13,919			10,425
Accumulated other comprehensive loss		(333	)		(373	)
		19,184			15,032
	$	32,355		$	26,108
The accompanying notes are an integral part of these consolidated financial statements.

Consolidated Statements of Stockholders’ Equity
In millions

Occidental Petroleum Corporation
and Subsidiaries

	Common Stock ^(a)			Treasury Stock			Additional Paid-in Capital ^(a)			Retained Earnings			Accumulated Other Comprehensive Income(Loss)
Balance, December 31, 2003	$	155		$	—		$	4,194		$	3,530		$	50
Net income		—			—			—			2,568			—
Other comprehensive income, net of tax		—			—			—			—			105
Dividends on common stock		—			—			—			(434	)		—
Issuance of common stock		—			—			8			—			—
Exercises of options and other, net		4			—			370			—			—
Balance, December 31, 2004	$	159		$	—		$	4,572		$	5,664		$	155
Net income		—			—			—			5,281			—
Other comprehensive loss, net of tax		—			—			—			—			(528	)
Dividends on common stock		—			—			—			(520	)		—
Issuance of common stock		—			—			16			—			—
Exercises of options and other, net		2			—			239			—			—
Purchases of treasury stock		—			(8	)		—			—			—
Balance, December 31, 2005	$	161		$	(8	)	$	4,827		$	10,425		$	(373	)
Net income		—			—			—			4,182			—
Other comprehensive income, net of tax		—			—			—			—			40
Dividends on common stock		—			—			—			(688	)		—
Issuance of common stock		11	^(b)		—			2,064	^(c)		—			—
Exercises of options and other, net		2			—			14			—			—
Purchases of treasury stock		—			(1,473	)		—			—			—
Balance, December 31, 2006	$	174		$	(1,481	)	$	6,905		$	13,919		$	(333	)

(a)	Restated to reflect a two-for-one stock split effected as a 100-percent stock dividend in August 2006. See Note 1 for further information.
(b)	Amount represents stock issued for the Vintage acquisition.
(c)	Includes $2,054 for stock issued for the Vintage acquisition.

Consolidated Statements of Comprehensive Income
In millions

For the years ended December 31,	2006			2005			2004
Net income	$	4,182		$	5,281		$	2,568
Other comprehensive income(loss) items:
Foreign currency translation adjustments ^(a)		5			(13	)		3
Derivative mark-to-market adjustments ^(b)		88			(330	)		7
Pension and post-retirement adjustments ^(c)		(168	)		—			—
Minimum pension liability adjustments		(3	)		(1	)		—
Reclassification of realized gains ^(d)		(59	)		(463	)		—
Unrealized gains on securities ^(e)		177			279			95
Other comprehensive (loss) income, net of tax		40			(528	)		105
Comprehensive income	$	4,222		$	4,753		$	2,673

(a)	Net of tax of $0, $13 and $1 in 2006, 2005 and 2004, respectively.
(b)	Net of tax of $50, $188 and $4 in 2006, 2005 and 2004, respectively.
(c)	Net of tax of $104 in 2006. See Note 13 for further information.
(d)	Net of tax of $34 and $264 in 2006 and 2005, respectively. Amounts represent the recognition of the 2006 gain on the partial sale of Lyondell shares and the 2005 gain due to Valero Energy Corporation’s acquisition of Premcor, Inc. and the subsequent sale of the Valero shares.
(e)	Net of tax of $102, $165 and $51 in 2006, 2005 and 2004, respectively.
The accompanying notes are an integral part of these consolidated financial statements.

Consolidated Statements of Cash Flows
In millions

Occidental Petroleum Corporation
and Subsidiaries

For the years ended December 31,	2006			2005			2004
CASH FLOW FROM OPERATING ACTIVITIES
Net income	$	4,182		$	5,281		$	2,568
Adjustments to reconcile net income to net cash provided by operating activities:
Discontinued Operations, net		253			(238	)		(162	)
Cumulative effect of changes in accounting principles, net		—			(3	)		—
Depreciation, depletion and amortization of assets		2,042			1,422			1,251
Reversal of tax reserves		—			(954	)		(47	)
Deferred income tax (benefit) provision		85			(74	)		173
Other noncash charges to income		588			812			415
Gains on disposition of assets, net		(118	)		(870	)		(1	)
Income from equity investments		(182	)		(232	)		(113	)
Gain on Lyondell stock issuance		—			—			(121	)
Dry hole and impairment expense		114			220			155
Changes in operating assets and liabilities:
Increase in accounts and notes receivable		(81	)		(670	)		(1,053	)
Increase in inventories		(77	)		(121	)		(92	)
Increase in prepaid expenses and other assets		(119	)		(36	)		(57	)
(Decrease) increase in accounts payable and accrued liabilities		(215	)		532			740
(Decrease) increase in current domestic and foreign income taxes		(57	)		201			92
Other operating, net		(234	)		(244	)		(149	)
Operating cash flow from continuing operations		6,181			5,026			3,599
Operating cash flow from discontinued operations		172			311			279
Net cash provided by operating activities		6,353			5,337			3,878
CASH FLOW FROM INVESTING ACTIVITIES
Capital expenditures		(3,005	)		(2,324	)		(1,720	)
Sale of businesses and disposal of property, plant and equipment, net		982			185			9
Purchase of businesses, net		(2,545	)		(2,126	)		(208	)
Purchase of short-term investments		(177	)		(185	)		(260	)
Sale of short-term investments		190			183			120
Sales of equity investments and available-for-sale investments		251			1,122			—
Equity investments and other, net		(74	)		83			(245	)
Investing cash flow from continuing operations		(4,378	)		(3,062	)		(2,304	)
Investing cash flow from discontinued operations		(5	)		(99	)		(124	)
Net cash used by investing activities		(4,383	)		(3,161	)		(2,428	)
CASH FLOW FROM FINANCING ACTIVITIES
Proceeds from long-term debt		173			236			60
Payments of long-term debt and capital lease liabilities		(1,066	)		(1,134	)		(239	)
Proceeds from issuance of common stock		7			13			7
Purchases of treasury stock		(1,473	)		(8	)		—
Repurchase of trust preferred securities		—			—			(466	)
Cash dividends paid		(646	)		(483	)		(424	)
Stock options exercised		46			126			238
Excess tax benefits related to share-based payments		140			36			—
Other financing, net		—			28			—
Financing cash flow from continuing operations		(2,819	)		(1,186	)		(824	)
Financing cash flow from discontinued operations		—			(1	)		3
Net cash used by financing activities		(2,819	)		(1,187	)		(821	)
(Decrease) Increase in cash and cash equivalents		(849	)		989			629
Cash and cash equivalents — beginning of year		2,188			1,199			570
Cash and cash equivalents — end of year	$	1,339		$	2,188		$	1,199
The accompanying notes are an integral part of these consolidated financial statements.

Notes to Consolidated Financial Statements

Occidental Petroleum Corporation
and Subsidiaries

NOTE 1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

NATURE OF OPERATIONS

In these Notes, the term "Occidental" or "the Company" refers to Occidental Petroleum Corporation (OPC) and/or one or more entities where it owns a majority voting interest (subsidiaries). Occidental is a multinational organization whose principal business segments are operated by its oil and gas subsidiaries and chemical subsidiaries. The subsidiaries and other affiliates in the oil and gas segment explore for, develop, produce and market crude oil and natural gas. The subsidiaries and other affiliates in the chemical segment (OxyChem) manufacture and market basic chemicals, vinyls and performance chemicals.

On August 1, 2006, Occidental effected a two-for-one stock split in the form of a stock dividend to shareholders of record as of that date with distribution of the shares on August 15, 2006. The total number of authorized shares of common stock and associated par value per share were unchanged by this action. All share and per-share amounts discussed and disclosed in this Annual Report on Form 10-K reflect the effect of the stock split.

PRINCIPLES OF CONSOLIDATION

The consolidated financial statements include the accounts of OPC, its subsidiaries, variable-interest entities (VIE) in which it is the primary beneficiary and its undivided interests in oil and gas exploration and production ventures. Occidental's proportionate share of oil and gas exploration and production ventures, in which it has a direct working interest, is accounted for by reporting its proportionate share of assets, liabilities, revenues, costs and cash flows 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 reclassified to conform to the 2006 presentation.

INVESTMENTS IN UNCONSOLIDATED ENTITIES

Investments in unconsolidated entities include both equity method 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. Occidental records its share of gains or losses that arise from equity-method investee stock issuances in the income statement. Occidental 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 and 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 realized. Upon disposal, the accumulated unrealized gain or loss included in OCI is transferred to income.

REVENUE RECOGNITION

Revenue is recognized from oil and gas production when title has passed to the customer, which occurs when the product is shipped. Revenue from marketing and trading activities 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. Revenue from all marketing and trading activities, including revenue from buy/sell arrangements with the same counterparty, is reported on a net basis.

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.

Occidental records revenue net of taxes that are assessed by governmental authorities on Occidental's customers.

RISKS AND UNCERTAINTIES

The process of preparing consolidated financial statements in conformity with United States generally accepted accounting principles (GAAP) 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, but 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.

Included in the accompanying consolidated balance sheet are deferred tax assets of $1.4 billion as of December 31, 2006, 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 temporary differences.

The accompanying consolidated financial statements include assets of approximately $9.2 billion as of December 31, 2006, and net sales of approximately $5.6 billion for the year ended December 31, 2006, relating to Occidental’s operations in countries outside North America. Occidental operates some of its oil and gas business in countries that occasionally have experienced political instability, armed conflict, civil unrest, security problems, restrictions on production equipment imports and sanctions that prevent continued operations, all of which increase Occidental's risk of loss or delayed or restricted production or may result in other adverse consequences. Occidental attempts to conduct its financial affairs so as to mitigate its exposure against such risks and would seek 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.

CASH AND CASH EQUIVALENTS

Cash equivalents are short-term, highly liquid investments that are readily convertible to cash. Cash equivalents totaled approximately $1.3 billion and $2.2 billion at December 31, 2006 and 2005, respectively.

SHORT-TERM INVESTMENTS

Occidental’s short-term investments consist of highly liquid debt securities classified as available-for-sale. Short-term investments are marked-to-market with any unrealized gains or losses included in accumulated other comprehensive income (AOCI). At December 31, 2006 and 2005, Occidental's short-term investments solely comprise auction-rate securities.

INVENTORIES

For the oil and gas segment, materials and supplies are valued at the lower of average cost or market. Inventories are reviewed periodically for obsolescence. Oil and natural gas liquids (NGLs) inventories and natural gas trading and storage inventory are valued at the lower of cost or market.

For the chemical segment, 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). Occidental accounts for materials and supplies using a weighted average cost method.

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 18).

The following table summarizes the activity of capitalized exploratory well costs for the past three years:

In millions	2006			2005			2004
Balance — Beginning of Year	$	46		$	5		$	—
Additions to capitalized exploratory well costs pending the determination of proved reserves		24			46			5
Reclassifications to property, plant and equipment based on the determination of proved reserves		(23	)		(2	)		—
Capitalized exploratory well costs charged to expense		(1	)		(3	)		—
Balance — End of Year	$	46		$	46		$	5

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, depletion and amortization (DD&A) and net of any impairment charges. For acquisitions of a business, PP&E cost is determined by an allocation of total purchase price to the components of PP&E based on their estimated fair values at the date of acquisition. 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. Occidental assesses assets for impairment by comparing undiscounted future cash flows of an asset to its carrying value. Impaired assets are written down to their estimated fair values, generally their estimated discounted future net pre-tax cash flows.

A portion of the carrying value of Occidental’s oil and gas properties are attributable to unproved properties. At December 31, 2006, the capitalized costs attributable to unproved properties, net of accumulated valuation allowance, were $1.7 billion. The acquisition of Vintage Petroleum, Inc. (Vintage) resulted in an addition of $1.3 billion of unproved properties in 2006. No goodwill was recorded on this transaction. During 2006, approximately $300 million of the unproved property amount was moved to proved properties. The unproved amounts are not subject to DD&A or impairment until a determination is made as to the existence of proven reserves. As exploration and development work progresses, if 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 ensure productive capacity is sustained. 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 sustained higher or lower product prices, which are particularly affected by both domestic and foreign competition, feedstock costs, energy prices, environmental regulations and technological changes.

Occidental performs 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. Occidental compares 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, regulations and remaining estimated useful life. Impaired assets are written down to their estimated fair values.

Due to a temporary decrease in demand for some of its products, Occidental temporarily idled an ethylene dichloride plant in June 2001 and a chlor-alkali plant in December 2001. Subsequent to the purchase of the Vulcan Materials Company (Vulcan) chemical assets, Occidental reviewed all of its chemical assets and decided to close its least competitive plants and upgrade the remaining operations. As a result of this review, Occidental recorded a $139 million pre-tax charge for the write-off of two previously idled chemical plants and one operating plant and an additional pre-tax charge of $20 million for the write-down of another chemical plant in 2005.

ACCRUED LIABILITIES — CURRENT

Accrued liabilities include accrued payroll, commissions and related expenses of $277 million and $240 million at December 31, 2006 and 2005, respectively.

ENVIRONMENTAL LIABILITIES AND EXPENDITURES

Many factors could result in changes to Occidental’s environmental reserves and reasonably possible range of loss. The most significant are:

Ø	The original cost estimate may have been inaccurate.
Ø	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.
Ø	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.
Ø	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:

Ø	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.
Ø	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 bioremediation, could significantly affect remediation costs.
Ø	Laws and regulations might change to impose more or less stringent remediation requirements.

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

In all three of these categories, Occidental records as a reserve its expected net cost of remedial activities, as adjusted by recognition for any nonperforming parties.

ASSET RETIREMENT OBLIGATIONS

In the period in which an asset retirement obligation is incurred or becomes reasonably estimable, Occidental recognizes the fair value of the liability if there is a legal obligation to dismantle the asset and reclaim or remediate the property at the end of its useful life. The liability amounts are based on future retirement cost estimates and incorporate many assumptions such as expected economic recoveries of oil and gas, time to abandonment, future inflation rates and the adjusted risk-free rate of interest. When the liability is initially recorded, Occidental capitalizes the cost by increasing the related PP&E balances. Over time, the liability is increased and expense is recognized for the change in its present value, and the initial capitalized cost is depreciated over the useful life of the asset. No market risk premium has been included in Occidental’s liability since no reliable estimate can be made at this time.

Occidental has identified conditional asset retirement obligations at a certain number of its facilities that are related mainly to plant decommissioning. Under Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 47, which Occidental adopted on December 31, 2005, Occidental was required to record the fair value of these conditional liabilities if they could be reasonably estimated. However, Occidental believes that there is an indeterminate settlement date for these asset retirement obligations because the range of time over which Occidental may settle these obligations is unknown or cannot be estimated. Therefore, Occidental cannot reasonably estimate the fair value of these liabilities. Occidental will recognize these conditional asset retirement obligations in the periods in which sufficient information becomes available to reasonably estimate their fair values.

The following table summarizes the activity of the asset retirement obligation, of which $360 million and $228 million is included in deferred credits and other liabilities - other, with the remaining current portion in accrued liabilities at December 31, 2006 and 2005, respectively.

For the years ended December 31, (in millions)	2006			2005
Beginning balance	$	233		$	206
Liabilities incurred		33			4
Liabilities settled		(13	)		(6	)
Accretion expense		19			15
Acquisitions and other		62			24
Revisions to estimated cash flows		42			(10	)
Ending balance	$	376		$	233

DERIVATIVE INSTRUMENTS

All derivative instruments required to be marked-to-market under Statement of Financial Accounting Standards (SFAS) No. 133, as amended, are carried at fair value. Cash flow hedge realized gains and losses, and any ineffectiveness, are classified within the net sales line item. Gains and losses are netted in the income statement and are netted on the balance sheets when a right of offset exists.

Occidental applies either fair value or cash flow hedge accounting when transactions meet specified criteria for 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 and is designated and documented as a hedge, 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 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 income or loss. Occidental discontinues hedge accounting when it determines 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; when a forecasted transaction is no longer deemed highly probable; or when the derivative is no longer designated as a hedge.

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 fixed-rate debt, approximates fair value, and the cost, if any, to terminate off-balance-sheet financial instruments is not significant.

STOCK-BASED INCENTIVE PLANS

Occidental has established several shareholder-approved stock-based incentive plans for certain employees (Plans) that are more fully described in Note 12. Beginning July 1, 2005, Occidental accounted for those Plans under SFAS No. 123(R), "Share Based Payments." Prior to July 1, 2005, Occidental applied the Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees,” intrinsic value accounting method for its stock-based incentive plans. A summary of Occidental’s accounting policy under each method follows below.

SFAS No. 123(R)

For restricted stock units (RSUs) and performance restricted share units (PRSUs), compensation expense is measured on the grant date using the quoted market price of Occidental’s common stock. For stock options (Options), stock-settled stock appreciation rights (SARs) and performance stock awards (PSAs), compensation expense is measured on the grant date using valuation models. Compensation expense for RSUs, PRSUs, Options, stock-settled SARs and PSAs, is recognized on a straight-line basis over the requisite service periods, which is generally over the awards’ respective vesting or performance periods. For the PSAs, every quarter until vesting, the cash-settled portion is revalued using valuation models and the stock settled portion is adjusted for any change in the number of shares expected to be issued based on the performance criteria. For the PRSUs, compensation expense is adjusted for any change in the number of shares expected to be issued based on the performance criteria. Any change in fair value is recognized as compensation expense. For cash-settled SARs issued prior to the adoption of SFAS 123(R), compensation expense is initially measured on the grant date using a valuation model and then is recorded on the accelerated amortization method over the vesting period. Changes in the fair value between the date of grant and the date when the cash-settled SARs are exercised are recognized as compensation expense. Occidental recognizes compensation expense for all graded vesting awards issued subsequent to the adoption of SFAS 123(R) on the straight-line method.

APB Opinion No. 25

Through June 30, 2005, compensation expense for Options and RSUs, if any, was measured as the difference between the quoted market price of Occidental's stock at the grant date, less the amount that the employee must pay to acquire the stock. Any compensation expense for these awards was recognized on a straight-line basis over the vesting periods of the respective awards. For PSAs, compensation expense was measured for each period based on the number of shares expected to vest and the changes in the quoted market value of Occidental's stock during the vesting period. Compensation expense or benefit for PSAs, as applicable, was recognized on a straight-line basis over the vesting periods of the awards. Compensation expense for SARs, which was recorded on the accelerated amortization method over the vesting period, was measured as the amount by which the quoted market value of Occidental's stock exceeded the SAR exercise price. The effect of changes in Occidental's share price between the date of grant and the date when the SARs were exercised or expired was recognized as compensation expense in each period.

SUPPLEMENTAL CASH FLOW INFORMATION

Cash payments, net of refunds, during the years 2006, 2005 and 2004 included federal, foreign and state income taxes of approximately $2.175 billion, $1.759 billion and $905 million, respectively. Interest paid (net of interest capitalized) totaled approximately $211 million, $253 million and $205 million for the years 2006, 2005 and 2004, respectively. Net cash payments for federal, foreign and state income taxes paid by discontinued operations during the years 2006, 2005 and 2004 were $57 million, $85 million and $26 million, respectively. (See Note 2 for detail of noncash investing and financing activities regarding certain acquisitions.)

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. Exchange-rate changes on transactions denominated in non-U.S. dollar functional currencies generated losses of zero in 2006, $9 million in 2005 and $13 million in 2004.

NOTE 2 BUSINESS COMBINATIONS AND ASSET ACQUISITIONS AND DISPOSITIONS

2006

In January 2006, Occidental completed the merger of Vintage into a wholly-owned Occidental subsidiary. As a result, Occidental acquired assets in Argentina, California, Yemen, Bolivia and the Permian Basin in Texas. Occidental paid approximately $1.3 billion in cash to former Vintage shareholders, issued approximately 56 million shares of Occidental common stock, which were valued at $2.1 billion, and assumed Vintage’s debt, which had an estimated fair market value of $585 million at closing. Occidental believes that the merger provides significant growth opportunities represented by Vintage’s assets in Argentina, California and Yemen, all of which will complement and enhance Occidental’s current operations and production.

The acquisition was accounted for in accordance with SFAS No. 141, “Business Combinations.” The results of Vintage’s operations have been included in the consolidated financial statements since January 30, 2006. The assets acquired and liabilities assumed were recorded at their estimated fair values at the acquisition date. The estimated fair value of PP&E consisted of $3.4 billion of proved properties and $1.3 billion of unproved properties. No goodwill was recorded on this transaction. The following table summarizes the allocation of the purchase price to Vintage’s assets and liabilities:

Balance at January 30, (in millions)	2006
Other current assets	$	336
Assets of discontinued operations		1,001
Property, plant and equipment, net		4,712
Other non-current assets		11
Total Assets Acquired	$	6,060
Other current liabilities	$	278
Liabilities of discontinued operations		30
Long-term debt, net		585
Deferred income taxes		1,606
Other long-term liabilities		155
Total Liabilities Assumed	$	2,654
Net Assets Acquired	$	3,406

Certain Vintage assets and their related liabilities were classified as held for sale as part of the allocation of the purchase price as Occidental intended at the time of acquisition to divest these assets. The results of operations for the assets that were held for sale and sold are not included in the revenue, cost or production amounts and were treated as discontinued operations as Occidental did not expect to generate any significant cash flows from, or have any continuing involvement with, the activities of these Vintage assets. During 2006, Occidental divested these assets for approximately $1.0 billion and recorded no gain or loss on these sales. On the December 31, 2006, consolidated balance sheet, the assets of discontinued operations amount includes approximately $22 million of the remaining amount of PP&E that is being held for sale and the liabilities of discontinued operations includes $4 million of liabilities held for sale. Net revenues and pre-tax income for discontinued operations related to these Vintage assets for the year ended December 31, 2006, were $869 million and $237 million, respectively.

The following unaudited pro forma summary presents the consolidated results of operations as if the acquisition of Vintage had occurred at the beginning of each year:

For the years ended December 31, (in millions) (unaudited)	2006		2005
Pro Forma Results of Operations
Revenues	$	18,227	$	16,300
Net income	$	4,148	$	5,374
Basic earnings per common share	$	4.86	$	6.23
Diluted earnings per common share	$	4.82	$	6.15

The unaudited pro forma data presented above use estimates and assumptions based on information currently available, and are not necessarily indicative of the results of operations of Occidental that would have occurred had such acquisition actually been consummated as of the beginning of the years presented, nor are they necessarily indicative of future results of operations.

In May 2006, Ecuador terminated Occidental's contract for the operation of Block 15, which comprised all of its oil producing operations in the country, and seized Occidental's Block 15 assets. The process resulting in this action began shortly after Occidental prevailed, by unanimous decision of an international arbitration panel subsequently upheld by a London court, in a legal dispute over tax refunds that Ecuador wrongfully withheld. Occidental immediately filed an arbitration claim against Ecuador, seeking redress for illegal confiscation of the Block 15 operations with the International Centre for Settlement of Investment Disputes in Washington, D.C., invoking the protections of the U.S. - Ecuador Bilateral Investment Treaty. As a result of the seizure, Occidental classified its Block 15 operations as discontinued operations. In 2006, Occidental recorded a net after-tax charge of $296 million in discontinued operations. This amount consists of after-tax charges for the write-off of the investment in Block 15 in Ecuador, as well as ship-or-pay obligations entered into with respect to the Oleoducto de Crudos Pesados Ltd. (OCP) pipeline in Ecuador to ship oil produced in Block 15, partially offset by $109 million after-tax income from operations for the first five months of 2006.

Occidental’s Block 15 assets and liabilities are classified as assets and liabilities of discontinued operations on the consolidated balance sheet at December 31, 2005, on a retrospective application basis. At December 31, 2005, Block 15 assets of discontinued operations were $426 million, which mainly consisted of PP&E. At December 31, 2006, liabilities of discontinued operations related to Ecuador were $321 million, which mainly consisted of the ship or pay obligations to the OCP pipeline. At December 31, 2005, liabilities of discontinued operations related to Ecuador were $136 million, which mainly consisted of accrued liabilities. Net revenues and pre-tax income (loss) for discontinued operations related to Ecuador for the year ended December 31, 2006, 2005 and 2004 were $275 million and $(529) million, including a pre-tax write-off of $(673) million, $611 million and $325 million, and $489 million and $269 million, respectively.

In September 2006, Occidental acquired oil and gas assets located in the Permian Basin in West Texas and California from Plains Exploration and Production Co. (Plains) for approximately $859 million in cash.

2005

In 2005, Occidental made several oil and gas producing property acquisitions in the Permian Basin for approximately $1.7 billion in cash. This was partially offset by cash proceeds totaling $171 million from dispositions of a portion of the acquired properties. No gain or loss was recorded for these dispositions.

In 2005, the Libyan authorities approved the terms of Occidental’s participation in the assets that it left in 1986. This re-entry agreement allowed Occidental to return to its Libyan operations on generally the same terms in effect when activities were suspended. Those assets consist of three producing contracts in the Sirte Basin and four exploration blocks. Occidental paid approximately $133 million in re-entry bonuses and capital adjustment and work-in-progress payments and is required to pay $10 million per year while it continues to operate in Libya, as reimbursements for past development costs associated with these assets. In addition, Occidental has committed to spend $90 million over the next five years in the four exploration blocks. Currently, Occidental’s rights in the producing fields extend through 2009 and early 2010.

Separately, in early 2005, Occidental participated in the EPSA IV exploration bid round in Libya. Occidental successfully bid on nine of the 15 areas available. Occidental is the operator of five onshore areas and has a 90-percent exploration working interest in each area. In addition, Occidental holds a 35-percent exploration working interest in four offshore areas. Woodside Petroleum Ltd. is the operator for the offshore areas. Occidental paid approximately $90 million in exploration lease bonuses for these nine new areas and committed to perform a minimum exploration work program valued at $125 million over the commitment period.

In July 2005, Occidental signed a new production-sharing contract (PSC) for the Mukhaizna oil field with the Government of the Sultanate of Oman. Under the terms of the new PSC, Occidental took over field operations on September 1, 2005, for a cost of $137 million. Occidental holds a 45-percent working interest.

In June 2005, Occidental completed the purchase of three basic chemical manufacturing facilities from Vulcan for $214 million in cash, plus contingent payments based upon the future performance of these facilities and the assumption of certain liabilities. In order to facilitate receipt of regulatory approval for this acquisition, Occidental divested one of the facilities.

2004

In January 2004, Occidental acquired a 1,300-mile oil pipeline and gathering system located in the Permian Basin for approximately $143 million in cash.

For strategic and economic reasons, Occidental exited the vinyl specialty resins business by closing the Pottstown, Pennsylvania manufacturing facility (Specialty Resins) effective January 5, 2005, and recorded an after-tax charge of $32 million as of December 31, 2004. Occidental's assets and liabilities related to Specialty Resins are classified as held for sale and as discontinued operations in the income statements for all periods presented. Specialty Resins' net sales included in discontinued operations were $1 million, $27 million and $98 million for 2006, 2005 and 2004, respectively, and net gains (losses) from discontinued operations were $2 million, $6 million and $(38) million, respectively.

NOTE 3 ACCOUNTING CHANGES

FUTURE ACCOUNTING CHANGES
FIN 48

SFAS No. 157

FSP AUG AIR-1

EITF Issue No. 06-4

In September 2006, the Emerging Issues Task Force (EITF) finalized the provisions of EITF Issue No. 06-4, “Accounting for Deferred Compensation and Postretirement Benefit Aspects of Endorsement Split-Dollar Life Insurance Arrangements.” This EITF Issue provides accounting guidance for endorsement split-dollar life insurance arrangements and require employers to recognize liability for future benefits in accordance with SFAS 106 or APB Opinion No. 12. The recognition and disclosure provisions of EITF Issue No. 06-4 are effective for fiscal years ending after December 15, 2007. Occidental is currently assessing the effect of this EITF Issue on its financial statements.

EITF Issue No. 06-5

In September 2006, the EITF finalized the provisions of EITF Issue No. 06-5, "Accounting for Purchase of Life Insurance-Determining the Amount That Could Be Realized in Accordance with FASB Technical bulletin No. 85-4.” This EITF Issue provides accounting guidance for life insurance policies and requires employers to consider and account for any additional amounts or restrictions under the terms of such policies. The recognition and disclosure provisions of EITF Issue No. 06-5 are effective for fiscal years beginning after December 15, 2006. Occidental will adopt this EITF Issue in the first quarter of 2007 and expects there will not be a material effect on the financial statements upon adoption.

RECENTLY ADOPTED ACCOUNTING CHANGES
SFAS No. 158

In September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans—an amendment of FASB Statements No. 87, 88, 106, and 132(R).” This statement requires an employer to recognize the overfunded or underfunded amounts of its defined benefit pension and postretirement plans as an asset or liability and recognize changes in the funded status of these plans in the year in which the changes occur through OCI, if they are not recognized in the income statement. The statement also requires a company to use the date of its fiscal year-end to measure the plans. The recognition and disclosure provisions of SFAS No. 158 are effective for fiscal years ending after December 15, 2006. The requirement to use the fiscal year-end as the measurement date is effective for fiscal years ending after December 15, 2008. Occidental adopted this statement on December 31, 2006. See Note 13 for further information.

SAB 108

In September 2006, the Securities and Exchange Commission issued Staff Accounting Bulletin (SAB) 108, “Financial Statements – Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements.” SAB 108 requires quantification of the impact of all prior year misstatements from both an income statement and a balance sheet perspective to determine if the misstatements are material. SAB 108 is effective for financial statements issued for fiscal years ending after November 15, 2006. Occidental adopted SAB 108 effective December 31, 2006 and there was no material effect on the financial statements upon adoption.

SFAS No. 123(R)

EITF Issue No. 04-13

In September 2005, the EITF finalized the provisions of EITF Issue No. 04-13, "Accounting for Purchases and Sales of Inventory with the Same Counterparty", which provides accounting guidance about whether buy/sell arrangements should be accounted for at historical cost and whether these arrangements should be reported on a gross or net basis. Buy/sell arrangements typically are contractual arrangements where the buy and sell agreements are entered into in contemplation of one another with the same counterparty. Occidental reports all buy/sell arrangements on a net basis and at historical cost. This EITF Issue was effective in the first interim period beginning after March 15, 2006. Occidental prospectively adopted this EITF Issue in the second quarter of 2006 and there was no material effect on the financial statements upon adoption.

NOTE 4 INVENTORIES

Inventories of approximately $204 million and $157 million were valued under the LIFO method at December 31, 2006 and 2005, respectively. Inventories consisted of the following:

Balance at December 31, (in millions)	2006			2005
Raw materials	$	70		$	81
Materials and supplies		304			177
Finished goods		525			558
		899			816
LIFO reserve		(74	)		(100	)
Total	$	825		$	716

NOTE 5 LONG-TERM DEBT

Long-term debt consisted of the following:

Balance at December 31, (in millions)	2006			2005
Occidental Petroleum Corporation
6.75% senior notes due 2012	$	368		$	371
8.45% senior notes due 2029		328			350
9.25% senior debentures due 2019		265			300
4.25% medium-term senior notes due 2010		227			253
10.125% senior debentures due 2009		222			222
7.2% senior debentures due 2028		200			200
4% medium-term senior notes due 2007		146			156
8.75% medium-term notes due 2023		76			100
11.125% senior notes due 2010		12			12
8.1% medium-term notes due 2008		10			10
7.375% senior notes due 2008 ^(a)		—			408
		1,854			2,382
Subsidiary Debt
Dolphin Energy Ltd. loans due 2009 ^(b) (5.76% as of December 31, 2006 and 4.47% as of December 31, 2005)		473			299
8.25% Vintage senior notes due 2012		276			—
3.6% to 7.5% unsecured notes due 2007 through 2018		171			242
		2,774			2,923
Less:
Unamortized premium (discount), net		16			(4	)
Current maturities		(171	)		(46	)
Total	$	2,619		$	2,873

(a)	The December 31, 2005 amount includes unamortized interest rate swap settlement net gains of $13 million.
(b)	The Dolphin Energy Ltd. loans include Occidental’s portion of the bridge loan and Islamic-law-compliant facility.

In September 2006, Occidental amended and restated its $1.5 billion bank credit (Credit Facility) to, among other things, lower the interest rate and extend the term to September 2011. The Credit Facility provides for the termination of the loan commitments and requires immediate repayment of any outstanding amounts if certain events of default occur or if Occidental files for bankruptcy. Occidental had not drawn down any amounts on the Credit Facility at December 31, 2006. None of Occidental's committed bank credits contain material adverse change (MAC) clauses or debt rating triggers that could restrict Occidental's ability to borrow under these lines. Occidental's credit facilities and debt agreements do not contain rating triggers that could terminate bank commitments or accelerate debt in the event of a ratings downgrade. Up to $350 million of the Credit Facility is available in the form of letters of credit. Borrowings under the Credit Facility bear interest at various benchmark rates, including LIBOR, plus a margin based on Occidental's senior debt ratings. Additionally, Occidental pays an annual facility fee (ranging from 0.06 percent to 0.08 percent in 2006) on the total commitment amount, which is based on Occidental's senior debt ratings.

In 2006, Occidental recorded $35 million of pre-tax charges to redeem all of its outstanding 7.375-percent senior notes due 2008 and all of its 7.875-percent Vintage senior subordinated notes due 2011 and to purchase in the open market and retire various amounts of Occidental and Vintage senior notes and unsecured subsidiary notes.

In 2005, Occidental recorded $42 million of pre-tax interest charges to redeem all of its outstanding 5.875-percent senior notes, 4.101-percent medium-term senior notes and 7.65-percent senior notes and to purchase in the open market and retire various amounts of Occidental senior notes and unsecured subsidiary notes.

At December 31, 2006, minimum principal payments on long-term debt subsequent to December 31, 2006, aggregated $2,774 million, of which $171 million is due in 2007, $10 million in 2008, $695 million in 2009, $239 million in 2010, $68 million in 2011, $644 million in 2012 and $947 million thereafter. These amounts do not include the net unamortized premium of $16 million. The unamortized premium is generally being amortized to interest expense on the effective interest method over the lives of the related issuances.

At December 31, 2006, under the most restrictive covenants of certain financing agreements, Occidental's capacity for additional unsecured borrowing was approximately $44.8 billion and the capacity for the payment of cash dividends and other distributions on, and for acquisitions of, Occidental’s capital stock was approximately $17.2 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 values of Occidental’s debt, at December 31, 2006 and 2005, were approximately $3.1 billion and $3.4 billion, respectively, compared with carrying values of approximately $2.8 billion and $2.9 billion, respectively.

NOTE 6 LEASE COMMITMENTS

The present value of minimum capital lease payments, net of the current portion, totaled $25 million at both December 31, 2006 and 2005. 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, 2006, future net minimum lease payments for capital and operating leases (excluding oil and gas and other mineral leases, utilities, taxes, insurance and maintenance expense) were the following:

In millions	Capital			Operating ^(a)
2007	$	1		$	167
2008		1			136
2009		1			117
2010		1			94
2011		1			77
Thereafter		33			767
Total minimum lease payments		38		$	1,358
Less:
Imputed interest		(13	)
Present value of minimum capital lease payments, net of current portion	$	25

(a)	At December 31, 2006, sublease rental amounts included in the future operating lease payments totaled $60 million, as follows (in millions): 2007—$8, 2008—$8, 2009—$10, 2010—$8, 2011—$8 and thereafter—$18.

Rental expense for operating leases, net of sublease rental income, was $199 million in 2006, $141 million in 2005 and $120 million in 2004. Rental expense was net of sublease income of $7 million in both 2006 and 2005 and $8 million in 2004.

NOTE 7 DERIVATIVE ACTIVITIES

Occidental's market risk exposures relate mainly to commodity prices and, to a lesser extent, interest rates and foreign currency exchange rates. Occidental has entered into derivative instrument transactions to reduce these price and rate fluctuations. A derivative is an instrument that, among other characteristics, derives its value from changes in 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.

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 have been 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. Occidental's use of derivatives in marketing and trading activities primarily relates to managing cash flows from third-party purchases, which includes Occidental’s periodic gas storage activities.

Production Hedges

Fair Value of Marketing and Trading Derivative Contracts

In millions	2006			2005
Fair value of contracts outstanding at beginning of year – unrealized (losses) gains	$	(457	)	$	30
Losses on changes for contracts realized or otherwise settled during the year		106			56
Changes in fair value attributable to changes in valuation techniques and assumptions		—			—
Losses or other changes in fair values		(4	)		(543	)^(a)
Fair value of contracts outstanding at end of year – unrealized losses	$	(355	)	$	(457	)

(a)	Primarily relates to production hedges.

	Maturity Periods
Source of Fair Value – unrealized (losses) gains	2007			2008 to 2009			2010 to 2011			2012 and thereafter			Total Fair Value
Prices actively quoted	$	(43	)	$	6		$	2		$	2		$	(33	)
Prices provided by other external sources		62			18			3			(1	)		82
Prices based on models and other valuation methods ^(a)		(63	)		(187	)		(154	)		—			(404	)
Total	$	(44	)	$	(163	)	$	(149	)	$	1		$	(355	)

(a)

INTEREST RATE RISK
General

Occidental’s exposure to changes in interest rates relates primarily to its long-term debt obligations.

In 2005, Occidental terminated all of its interest-rate swaps that were accounted for as fair-value hedges. These hedges had effectively converted approximately $1.7 billion of fixed-rate debt to variable-rate debt. The fair value of the swaps at termination resulted in a gain of approximately $20 million, which was recorded into income when the debt was paid in 2005 and 2006. The amount of interest expense recorded in the income statement was lower, as a result of the swaps and recognition of the gain, by approximately $13 million, $21 million and $56 million for the years ended December 31, 2006, 2005 and 2004, respectively.

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 unamortized loss on the hedges at December 31, 2006 was approximately $18 million after-tax, which is recorded in AOCI and is being recognized in earnings over the lease term of 26 years on a straight-line basis.

CREDIT RISK

FOREIGN CURRENCY RISK

DERIVATIVE AND FAIR VALUE DISCLOSURES

The following table shows derivative financial instruments included in the consolidated balance sheets:

Balance at December 31, (in millions)	2006		2005
Derivative financial instrument assets
Receivables from joint ventures, partnerships and other	$	248	$	286
Long-term receivables, net		61		178
	$	309	$	464
Derivative financial instrument liabilities
Accrued liabilities	$	291	$	387
Deferred credits and other liabilities – other		384		564
	$	675	$	951

The following table summarizes net after-tax derivative activity recorded in AOCI:

Balance at December 31, (in millions)	2006			2005
Beginning Balance	$	(347	)	$	(17	)
Gains (losses) from changes in cash flow hedges		32			(289	)
Amount reclassified to income		56			(41	)
Ending Balance	$	(259	)	$	(347	)

During the next twelve months, Occidental expects that approximately $11 million of net derivative after-tax losses included in AOCI, based on their valuation at December 31, 2006, will be reclassified into earnings. Hedge ineffectiveness did not have a material impact on earnings for the years ended December 31, 2006, 2005 and 2004.

NOTE 8 ENVIRONMENTAL LIABILITIES AND EXPENDITURES

ENVIRONMENTAL REMEDIATION

Occidental manages its environmental remediation efforts through a wholly owned subsidiary, Glenn Springs Holdings, Inc., which reports its results directly to Occidental’s corporate management. The following table presents Occidental's environmental remediation reserves, the current portion of which is included in accrued liabilities ($79 million in 2006, $83 million in 2005 and $76 million in 2004) and the remainder in deferred credits and other liabilities — other ($333 million in 2006, $335 million in 2005 and $299 million in 2004). The reserves are grouped by three categories of environmental remediation sites:

$ amounts in millions	2006			2005			2004
	Number of Sites	Reserve Balance		Number of Sites	Reserve Balance		Number of Sites	Reserve Balance
CERCLA & equivalent sites	105	$	226	128	$	236	125	$	239
Active facilities	21		116	18		114	16		75
Closed or sold facilities	40		70	39		68	39		61
Total	166	$	412	185	$	418	180	$	375

The following table shows environmental reserve activity for the past three years:

In millions	2006			2005			2004
Balance - Beginning of Year	$	418		$	375		$	372
Remediation expense and interest accretion		48			63			60
Changes from acquisitions/dispositions		17			45			6
Payments		(71	)		(71	)		(63	)
Other	—			6			—
Balance - End of Year	$	412		$	418		$	375

CERCLA and Equivalent Sites

As of December 31, 2006, OPC or certain of its subsidiaries have been named in 105 CERCLA or state equivalent proceedings, as shown below.

Description ($ amounts in millions)	Number of Sites	Reserve Balance
Minimal/No exposure ^(a)	85	$	6
Reserves between $1-10 MM	14		55
Reserves over $10 MM	6		165
Total	105	$	226

(a)

Active Facilities

Certain subsidiaries of OPC are currently addressing releases of substances from past operations at 21 active facilities. Five facilities — a chemical plant in Louisiana, a phosphorous recovery operation in Tennessee, a chemical plant in Texas, a chemical plant in Kansas and certain oil and gas properties in the southwestern United States — account for 69 percent of the reserves associated with these facilities.

Closed or Sold Facilities

There are 40 sites formerly owned or operated by certain subsidiaries of OPC that have ongoing environmental remediation requirements in which OPC or its subsidiaries are involved. Five sites account for 70 percent of the reserves associated with this group. The five 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, a closed Occidental Chemical Corporation (OCC) chemical plant in Pennsylvania, a closed landfill in western New York and a water-treatment facility at a former OCC chemical plant in North Carolina.

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	2006		2005		2004
Operating Expenses
Oil and Gas	$	95	$	65	$	51
Chemical	73		67		59
	$	168	$	132	$	110
Capital Expenditures
Oil and Gas	$	55	$	43	$	44
Chemical	25		21		12
	$	80	$	64	$	56
Remediation Expenses
Corporate	$	47	$	62	$	59

NOTE 9 LAWSUITS, CLAIMS, COMMITMENTS, CONTINGENCIES AND RELATED MATTERS

OPC or certain of its subsidiaries have been named in many 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 or certain of its subsidiaries also have been named in proceedings under CERCLA and similar federal, state, local and foreign 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.

Since 2004, OCC has been served with ten lawsuits filed in Nicaragua by approximately 2,600 individual plaintiffs. These individuals allege that they have sustained several billion dollars of personal injury damages as a result of their alleged exposure to a pesticide. OCC is aware of, but has not been served in, 24 additional cases in Nicaragua, which Occidental understands make similar allegations. In the opinion of management, the claims against OCC are without merit because, among other things, OCC believes that none of the pesticide it manufactured was ever sold or used in Nicaragua. Under the applicable Nicaraguan statute, defendants are required to pay pre-trial deposits so large as to effectively prohibit defendants from participating fully in their defense. OCC filed a response to the complaints contesting jurisdiction without posting such pre-trial deposit. In 2004, the judge in one of the cases (Osorio Case), ruled the court had jurisdiction over the defendants, including OCC, and that the plaintiffs had waived the requirement of the pre-trial deposit. In order to preserve its jurisdictional defense, OCC elected not to make a substantive appearance in the Osorio Case. In 2005, the judge in the Osorio Case entered judgment against several defendants, including OCC, for damages totaling approximately $97 million. In December 2006, the court in a second case in Nicaragua (Rios Case) entered a judgment against several defendants, including OCC, for damages totaling approximately $800 million. While preserving its jurisdictional defenses, OCC has appealed the judgments in the Osorio and Rios Cases. OCC has no assets in Nicaragua and, in the opinion of management, any judgment rendered under the statute, including in the Osorio and Rios Cases, would be unenforceable in the United States.

At December 31, 2006, commitments for major capital expenditures during 2007 and thereafter were approximately $787 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, 2006, 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 $16 million, which was payable as follows (in millions): 2007—$12 and 2008—$4. Fixed payments under these agreements were $18 million in 2006, $17 million in 2005 and $19 million in 2004.

Occidental has certain other commitments under contracts, guarantees and joint ventures, including purchase commitments for goods and services at market-related prices and certain other contingent liabilities. Some of these commitments, although not fixed or determinable, involve capital expenditures and are part of the $3.3 to $3.4 billion in capital expenditures estimated for 2007.

At December 31, 2006, the notional amount of the guarantees that are subject to the reporting requirements of FIN 45 was approximately $270 million, which consists of Occidental’s guarantee of equity investees’ debt, primarily from the Dolphin Project equity investment, and other commitments.

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, 2006, Occidental is not aware of circumstances it believes would reasonably be expected to lead to future indemnity claims against it in connection with these transactions that would result in payments materially in excess of reserves.

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
2006	$	4,521	$	3,380	$	7,901
2005	$	4,547	$	2,420	$	6,967
2004	$	2,412	$	1,633	$	4,045

The provisions (credits) for domestic and foreign income and other taxes from continuing operations consisted of the following:

For the years ended December 31, (in millions)	U.S. Federal			State and Local			Foreign			Total
2006
Current	$	1,457		$	120		$	1,804		$	3,381
Deferred		149			(13	)		(51	)		85
	$	1,606		$	107		$	1,753		$	3,466
2005
Current	$	612		$	126		$	1,263		$	2,001
Deferred		(63	)		(9	)		(2	)		(74	)
	$	549		$	117		$	1,261		$	1,927
2004
Current	$	695		$	45		$	726		$	1,466
Deferred		184			17			(28	)		173
	$	879		$	62		$	698		$	1,639

As a result of changes in compensation programs in 2006, Occidental wrote off approximately $40 million of the related deferred tax asset that had been recognized in the financial statements prior to the change. The 2005 federal income tax provision includes a $619 million tax benefit related to the resolution of foreign tax credit issues with the Internal Revenue Service (IRS) and a $335 million tax benefit due to the reversal of tax reserves no longer required. The 2005 income tax provision also includes a net $10 million charge related to a state tax issue. The 2004 federal income tax provision includes tax benefits of $47 million resulting from the reversal of tax contingency reserves no longer required due to the settlement of issues with the Internal Revenue Service.

The following is a reconciliation, stated as a percentage of pre-tax income, of the United States statutory federal income tax rate to Occidental’s effective tax rate on income from continuing operations:

For the years ended December 31,	2006		2005		2004
United States federal statutory tax rate	35	%	35	%	35	%
Operations outside the United States	8		6		6
State taxes, net of federal benefit	1		1		1
Reversal of tax reserves	—		(13	)	(1	)
Other	—		(1	)	—
Tax rate provided by Occidental	44	%	28	%	41	%

The tax effects of temporary differences resulting in deferred income taxes at December 31, 2006 and 2005 were as follows:

	2006					2005
Tax effects of temporary differences (in millions)	Deferred Tax Assets			Deferred Tax Liabilities		Deferred Tax Assets			Deferred Tax Liabilities
Property, plant and equipment differences	$	189		$	3,174	$	44		$	1,554
Investments including partnerships		—			217		—			221
Environmental reserves		162			—		184			—
Postretirement benefit accruals		233			—		139			—
Deferred compensation and benefits		208			—		202			—
Asset retirement obligations		82			—		66			—
Derivatives		70			—		184			—
Foreign tax credit carryforward		133			—		132			—
State income taxes		106			—		93			—
All other		364			108		241			97
Subtotal		1,547			3,499		1,285			1,872
Valuation allowance		(183	)		—		(175	)		—
Total deferred taxes	$	1,364		$	3,499	$	1,110		$	1,872

Included in total deferred tax assets was a current portion aggregating $190 million and $200 million as of December 31, 2006 and 2005, respectively, that was reported in prepaid expenses and other.

Occidental has, as of December 31, 2006, foreign tax credit carryforwards of $133 million which expire in varying amounts through 2016 and various state net operating loss carryforwards which have varying carryforward periods through 2025. Occidental established a valuation allowance against these foreign tax credit carryforwards and state net operating losses as the Company believes these assets will not be utilized in the statutory carryforward periods. In addition, Occidental establishes a valuation allowance against deferred tax assets resulting from deductible temporary differences when it believes future benefit is unlikely to be realized.

A deferred tax liability 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 aggregating approximately $5.4 billion at December 31, 2006, as it is Occidental’s intention, generally, to reinvest such earnings permanently. If the earnings of these foreign subsidiaries were not indefinitely reinvested, an additional deferred tax liability of approximately $200 million would be required, assuming utilization of available foreign tax credits.

The discontinued operations include an income tax benefit of $209 million in 2006, and a charge of $96 million in 2005 and $46 million in 2004.

The cumulative effect of changes in accounting principles was reduced by an income tax charge of $2 million in 2005.

Additional paid-in capital was credited $140 million in 2006, $74 million in 2005 and $75 million in 2004 for a tax benefit from the exercise of certain stock based compensation awards.

NOTE 11 STOCKHOLDERS' EQUITY

The following is an analysis of common stock:

(shares in thousands)		Common Stock
Balance, December 31, 2003		774,096
Issued		1,627
Options exercised and other, net		17,732
Balance, December 31, 2004		793,455
Issued		1,510
Options exercised and other, net		9,465
Balance, December 31, 2005		804,430
Issued		57,257
Options exercised and other, net		8,992
Balance, December 31, 2006		870,679

In May 2006, Occidental amended its Restated Certificate of Incorporation to increase the number of authorized shares of common stock to 1.1 billion. The par value per share remained unchanged.

TREASURY STOCK

In 2006, the Board of Directors authorized a treasury stock purchase program under which Occidental was authorized to purchase up to 40 million shares of its common stock, increased to 55 million in February 2007. Additionally, Occidental purchased shares from the trustee of its defined contribution savings plan. In 2006, Occidental purchased 30.6 million shares under the programs at an average cost of $48.20 per share.

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, 2006, 2005 and 2004, Occidental had no outstanding shares of preferred stock.

EARNINGS PER SHARE

Basic earnings per share was computed by dividing net income by the weighted average number of common shares outstanding during each year, including vested but unissued share and share units. The computation of diluted earnings per share further reflects the dilutive effect of stock options and stock-settled SARs.

The following are the share amounts used to compute the basic and diluted earnings per share for the years ended December 31:

In millions	2006		2005	2004
Basic Earnings per Share
Weighted average shares outstanding	860.9		799.9	785.3
Weighted average treasury shares	(15.9	)	—	—
Vested/unissued restricted units	4.3		3.2	2.4
Deferred shares and other	3.3		3.5	3.5
Basic Shares Outstanding	852.6		806.6	791.2
Diluted Earnings per Share
Basic shares outstanding	852.6		806.6	791.2
Dilutive effect of options and stock-settled SARs outstanding	5.9		9.8	9.5
Dilutive effect of unvested/unissued restricted units	1.9		1.8	1.6
Dilutive Shares	860.4		818.2	802.3

ACCUMULATED OTHER COMPREHENSIVE LOSS

Accumulated other comprehensive loss consisted of the following after-tax (losses) gains:

Balance at December 31, (in millions)	2006			2005
Foreign currency translation adjustments	$	(24	)	$	(29	)
Derivative mark-to-market adjustments		(259	)		(347	)
Pension and post-retirement adjustments ^(a)		(168	)		—
Minimum pension liability adjustments		—			3
Unrealized gains on securities		118			—
Total	$	(333	)	$	(373	)

(a)	See Note 13 for further information.

NOTE 12 STOCK-BASED INCENTIVE PLANS

Occidental has established several Plans that provide for stock-based awards in the form of Options, restricted stock, RSUs, stock bonuses, SARs, PSAs, PRSUs and dividend equivalents. These awards were granted under the 1995 Incentive Stock Plan (1995 ISP), 2001 Incentive Compensation Plan (2001 ICP) and the 2005 Long-Term Incentive Plan (2005 LTIP). No further awards will be granted under the 1995 ISP and 2001 ICP; however, certain 1995 ISP and 2001 ICP award grants were outstanding at December 31, 2006. An aggregate of 34 million shares of Occidental common stock are reserved for issuance under the 2005 LTIP and at December 31, 2006, approximately 14.5 million shares of Occidental common stock were available for future awards. Occidental also has a 1996 Restricted Stock Plan for Non-Employee Directors (1996 DRSP), under which non-employee directors received awards of restricted stock as additional compensation for their services as members of the Board of Directors. No further awards will be granted under the 1996 DRSP. All non-employee director awards are now granted under the 2005 LTIP. During 2006, non-employee directors were granted awards for 59,800 shares of restricted stock that fully vested on the grant date. No awards that have been granted to directors may be sold or transferred during the director’s period of service as a member of the Board. Compensation expense for these awards was measured using the quoted market price of Occidental's common stock on the grant date and was recognized at grant date.

Adoption of SFAS No. 123(R)

As discussed in Note 3, on July 1, 2005, Occidental changed its method of accounting for stock-based compensation from the APB Opinion No. 25 intrinsic value accounting method to the fair value recognition provisions of SFAS No. 123(R). Prior to July 1, 2005, Occidental had already been expensing its SARs, RSUs and PSAs. On July 1, 2005, Occidental began expensing its Options and recording compensation expense for all its other stock-based incentive awards using fair value amounts in accordance with SFAS No. 123(R).

The table below summarizes certain stock-based incentive amounts for the year (all amounts in millions):

Year Ended December 31,	2006		2005
Compensation expense	$	211	$	186
Income tax benefit recognized in the income statement	$	77	$	68
Intrinsic value of options and stock-settled SAR exercises	$	168	$	217
Liabilities paid ^(a)	$	34	$	11
Fair value of RSUs and PSAs vested during the year ^(b)	$	107	$	80

(a)	Includes liabilities paid under the cash-settled SARs.
(b)	As measured on the vesting date for RSUs and the stock-settled portion of the PSAs.

As of December 31, 2006, there was $256 million of pre-tax unrecognized compensation expense related to all unvested stock-based incentive award grants. This expense is expected to be recognized over a weighted average period of 2.1 years.

STOCK OPTIONS AND SARS

Certain employees are granted Options that are settled in physical stock and SARs that are settled either only in stock or only in cash. Exercise prices of the Options and SARs are equal to the quoted market value of Occidental’s stock on the grant date. Generally, the Options and SARs vest ratably over three years with a maximum term of ten years. These Options and SARs may be forfeited or accelerated under certain circumstances.

The fair value of each Option or stock-settled SAR is measured on the grant date using the Black Scholes option valuation model and expensed on a straight-line basis over the vesting period. The expected life is estimated based on the actual weighted average life of historical exercise activity of the grantee population at the grant date. The volatility factors are based on the historical volatilities of Occidental common stock over the expected lives as estimated on the grant date. The risk-free interest rate is the implied yield available on zero coupon (US Treasury Strip) T-notes at the grant date with a remaining term equal to the expected life. The dividend yield is the expected annual dividend yield over the expected life, expressed as a percentage of the stock price on the grant date. Estimates of fair value are not intended to predict actual future events or the value ultimately realized by employees who receive stock-based incentive awards, and subsequent events may not be indicative of the reasonableness of the original estimates of fair value made by Occidental.

The grant date assumptions used in the Black Scholes valuation for Options and stock-settled SARs were as follows:

Year Granted	2006	2005	2004	2003
Assumptions used:
Risk-free interest rate	5.0%	3.7%	3.4%	1.6%
Dividend yield	1.4%	1.5%	2.2%	3.4%
Volatility factor	26%	27%	21%	21%
Expected life (years)	5.5	5.5	3.6	2.4

The grant date fair value of each stock-settled SAR granted in 2006 and 2005 was $14.77 and $10.76, respectively. The grant date fair value of each Option granted in 2004 and 2003 was $4.02 and $1.60, respectively. The fair value of the cash-settled SARs is also estimated using the Black Scholes model and is recalculated using updated assumptions each quarter until they are exercised. Changes in the fair value between the date of grant and the date when the cash-settled SARs are exercised are recognized as compensation expense.

The following is a summary of Option and SAR transactions during 2006:

2006

Stock-
Settled
SARs &
Options
(000's)

Weighted
Average
Exercise
Price

Weighted
Average
Remaining
Contractual
Term (yrs)

Aggregate
Intrinsic
Value
(000’s)

Cash-
Settled
SARs
(000's)

Weighted
Average
Exercise
Price

Weighted
Average
Remaining
Contractual
Term (yrs)

Aggregate
Intrinsic
Value
(000’s)

Beginning balance,
January 1, 2006

22,980

19.43

6,327

24.66

Granted

3,138

50.45

—

Exercised

(13,224

)

14.15

(1,068

)

24.66

Forfeited or expired

(42

)

14.91

(49

)

24.66

Ending balance,
December 31, 2006

12,852

32.45

7.8

210,481

5,210

24.66

7.5

125,916

Exercisable at
December 31, 2006

6,537

21.23

6.6

180,400

2,908

24.66

7.5

70,276

RSUS

Certain employees are awarded the right to receive RSUs that vest ratably three and five years after the grant date and can be forfeited or accelerated under certain conditions. Dividend equivalents are paid during the vesting period. Compensation expense for RSUs is measured on the grant date using the quoted market price of Occidental's common stock on the grant date. The weighted average grant date fair values of the RSUs granted in 2006 and 2005 were $50.45 and $40.91, respectively.

A summary of changes in Occidental’s unvested RSUs during the year ended December 31, 2006, is presented below:

	2006
	RSUs (000’s)		Weighted Average Grant Date Fair Value
Unvested at January 1	3,781		$	32.94
Granted	926		$	50.45
Vested	(1,602	)	$	29.68
Forfeitures	(23	)	$	46.18
Unvested at December 31	3,082		$	39.79

PERFORMANCE-BASED AWARDS
PRSUs

Certain executives are awarded PRSUs with a performance measure based on Occidental’s three-year cumulative return on equity with payout amounts varying from zero to 200 percent of the target award. The PRSUs vest at the end of the three-year period following the grant date if performance targets are certified as being met. Compensation expense is measured on the grant date using the quoted market price of Occidental’s common stock and the number of shares expected to be issued based on the performance criteria. Compensation expense is adjusted during the vesting period only for changes in expected share payout. Cumulative dividend equivalents are paid in cash at the end of the performance period for the number of shares certified for payout.

A summary of Occidental’s PRSUs issued during the year ended December 31, 2006, is presented below:

	2006
	PRSUs (000’s)	Weighted Average Grant Date Fair Value
Unvested at January 1	—	$	—
Granted or issued	758	$	50.45
Unvested at December 31	758	$	50.45

PSAs

Certain executives are awarded PSAs that vest at the end of the four-year period following the grant date if performance targets are certified as being met, with payouts that range from zero to 200 percent of the target award. Dividend equivalents for target shares are paid during the performance period. In June 2005, the holders of substantially all of Occidental’s unvested PSAs agreed to modify the settlement provisions to provide that the first 100 percent payout will be settled only in stock and any payout in excess of 100 percent will be settled only in cash. There was no incremental compensation expense recorded at the time of the modification.

The fair values of the stock settled portion of PSAs are measured on the grant date using a Monte Carlo simulation model that uses the assumptions noted in the following table. The expected life is based on the vesting period (Term). The volatility factors are based on the historical volatilities of Occidental stock over the Term. The risk-free interest rate is the implied yield available on zero coupon (US Treasury Strip) T-notes at the time of grant with a remaining term equal to the Term. The dividend yield is the expected annual dividend yield over the Term, expressed as a percentage of the stock price on the grant date. Estimates of fair value are not intended to predict actual future events or the value ultimately realized by the employees who receive the awards, and subsequent events may not be indicative of the reasonableness of the original estimates of fair value made by Occidental. The fair values of the underlying Occidental stock as of the grant dates of the PSAs granted in 2006 and 2005 were $39.94 and $29.18, respectively.

The grant-date assumptions used in the Monte Carlo simulation model for stock-settled PSAs were as follows:

Year Granted	2006	2005	2004	2003
Assumptions used:
Risk-free interest rate	4.0%	3.3%	3.0%	3.1%
Dividend yield	1.7%	1.9%	2.5%	3.5%
Volatility factor	32%	21%	29%	31%
Expected life (years)	4	4	4	4

The fair value of the cash-settled portion of PSAs is also estimated using a Monte Carlo simulation model each quarter, through vesting, using updated assumptions. Changes in fair value of the cash-settled portion of the PSAs are recorded as compensation expense.

A summary of Occidental’s unvested PSAs as of December 31, 2006 and changes during the year ended December 31, 2006, is presented below:

	2006
	PSAs (000’s)		Grant Date Fair Value of Occidental Stock
Unvested at January 1 ^(a)	1,838		$	17.51
Granted ^{(a, b)}	199		$	39.94
Vested ^(c)	(620	)	$	13.27
Forfeitures	(15	)		N/A
Unvested at December 31 ^(a)	1,402		$	19.69

(a)	Unvested awards and award grants are presented at the target payouts.
(b)	Actual payout may be up to 200 percent of this amount.
(c)	The weighted-average payout at vesting was 161 percent of the target.

PRO-FORMA INFORMATION

Occidental adopted SFAS No. 123(R) on July 1, 2005. The following table shows the pro forma net income and earnings per share that Occidental would have recorded if compensation expense were determined using SFAS No. 123(R) for these periods (amounts in millions, except per share amounts).

	2005			2004
Net Income	$	5,281		$	2,568
Add: Stock-based compensation included in net income, net of tax, under APB Opinion No. 25 ^(a)		104			47
Deduct: Stock-based compensation, net of tax, determined under SFAS No. 123(R) fair value method ^(a)		(112	)		(61	)
Pro forma net income	$	5,273		$	2,554
Earnings per share:
Basic — as reported	$	6.55		$	3.24
Basic — pro forma	$	6.54		$	3.23
Diluted — as reported	$	6.45		$	3.20
Diluted — pro forma	$	6.44		$	3.18

(a)	The 2005 amounts include only the first six months of 2005 before SFAS 123(R) was adopted.

NOTE 13 RETIREMENT PLANS AND POSTRETIREMENT BENEFITS

Occidental has various benefit plans for its salaried, domestic union and nonunion hourly, and certain foreign national employees.

Defined Contribution 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 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 $70 million, $61 million and $60 million as of December 31, 2006, 2005 and 2004, respectively, and Occidental expensed $74 million in 2006, $66 million in 2005 and $59 million in 2004 under the provisions of these defined contribution and supplemental retirement plans.

Defined Benefit Plans

Participation in the defined benefit plans is limited and approximately 1,400 domestic and 1,100 foreign national employees, mainly union, nonunion hourly and certain employees that joined Occidental from acquired operations with grandfathered benefits, are currently accruing benefits under these plans.

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.

Other Postretirement Benefit 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 $120 million in 2006, $104 million in 2005 and $98 million in 2004.

Adoption of SFAS No. 158

As discussed in Note 3, on December 31, 2006, Occidental adopted the provisions of SFAS No. 158. This statement requires an employer to recognize the overfunded or underfunded amounts of its defined benefit pension and postretirement plans as an asset or liability and recognize changes in the funded status of these plans in the year in which the changes occur through OCI, if they are not recognized in the income statement. The following table shows the effect of adopting SFAS No. 158 on the consolidated balance sheet:

As of December 31, 2006 (in millions)	Debit/(Credit)
Other assets	$	(42	)
Deferred credits and other liabilities – other	$	(233	)
Deferred and other domestic and foreign income taxes	$	104
Minority interest	$	3
Accumulated other comprehensive loss	$	168

Obligations and Funded Status

Occidental uses a measurement date of December 31 for all defined benefit pension and postretirement benefit plans.

	Pension Benefits						Postretirement Benefits
							Unfunded Plans						Funded Plans
For the years ended December 31, (in millions)	2006			2005			2006			2005			2006			2005
Changes in benefit obligation:
Benefit obligation — beginning of year	$	492		$	448		$	614		$	586		$	26		$	25
Service cost — benefits earned during the period		11			12			10			9			—			—
Interest cost on projected benefit obligation		27			25			33			32			2			1
Actuarial (gain) loss		(6	)		16			16			9			1			1
Foreign currency exchange rate changes		2			5			—			—			—			—
Acquisitions ^(a)		28			4			—			26			1			—
Benefits paid		(30	)		(24	)		(54	)		(51	)		(1	)		(1	)
Special termination benefits ^(b)		—			4			—			3			—			—
Plan amendments		(1	)		2			—			—			—			—
Benefit obligation — end of year	$	523		$	492		$	619		$	614		$	29		$	26
Changes in plan assets:
Fair value of plan assets — beginning of year	$	424		$	398		$	—		$	—		$	2		$	1
Actual return on plan assets		68			32			—			—			—			—
Foreign currency exchange rate changes		1			1			—			—			—			—
Employer contribution		66			17			—			—			1			2
Benefits paid		(30	)		(24	)		—			—			(1	)		(1	)
Acquisitions ^(a)		27			—			—			—			1			—
Fair value of plan assets — end of year	$	556		$	424		$	—		$	—		$	3		$	2
Funded (unfunded) status:	$	33		$	(68	)	$	(619	)	$	(614	)	$	(26	)	$	(24	)

(a)	Relates to the acquisition of Tidelands in 2006 and Vulcan operating assets in 2005.
(b)	Relates to the Pottstown plant closure.

The projected benefit obligation, accumulated benefit obligation and fair value of plan assets for defined benefit pension plans with an accumulated benefit obligation in excess of plan assets were $96 million, $90 million and $0, respectively, as of December 31, 2006, and $94 million, $91 million and $4 million, respectively, as of December 31, 2005. The projected benefit obligation, accumulated benefit obligation and fair value of plan assets for defined benefit pension plans with plan assets in excess of the accumulated benefit obligation were $427 million, $404 million and $556 million, respectively, as of December 31, 2006, and $398 million, $377 million, and $420 million, respectively, as of December 31, 2005.

Occidental has 401(h) accounts established within certain defined benefit pension plans. These plans allow Occidental to fund postretirement medical benefits for employees at two of its operations. Contributions to these 401(h) accounts are made at Occidental's discretion. All of Occidental's other postretirement benefit plans are unfunded.

Amounts recognized in the consolidated balance sheets consist of:

	Pension Benefits						Postretirement Benefits
							Unfunded Plans						Funded Plans
As of December 31, (in millions)	2006			2005			2006			2005			2006			2005
Other assets	$	135		$	116	^(a)	$	—		$	—		$	—		$	—
Accrued liabilities		(3	)		—			(53	)		(50	)		—			—
Deferred credits and other liabilities – other		(99	)		(92	)		(566	)		(348	)		(26	)		(12	)
	$	33		$	24		$	(619	)	$	(398	)	$	(26	)	$	(12	)

(a)	Amount includes $4 million classified as prepaid expenses and other.

At December 31, 2006, AOCI included the following after-tax balances:

	Pension Benefits		Postretirement Benefits
			Unfunded Plans		Funded Plans
(in millions)	2006		2006		2006
Net loss	$	28	$	128	$	7
Prior service cost		1		4		—
	$	29	$	132	$	7

Occidental does not expect any plan assets to be returned during 2007.

Components of Net Periodic Benefit Cost and Other Amounts Recognized in OCI

	Pension Benefits									Postretirement Benefits
										Unfunded Plans						Funded Plans
For the years ended December 31, (in millions)	2006			2005			2004			2006		2005		2004		2006		2005		2004
Net periodic benefit costs:
Service cost — benefits earned during the period	$	11		$	12		$	12		$	10	$	9	$	7	$	—	$	—	$	1
Interest cost on benefit obligation		27			25			23			33		32		32		2		1		1
Expected return on plan assets		(33	)		(32	)		(25	)		—		—		—		—		—		—
Amortization of prior service cost		1			1			1			1		1		1		—		—		—
Recognized actuarial loss		1			—			2			16		14		11		1		1		—
Cost of special termination benefits ^(a)		—			4			—			—		3		—		—		—		—
Currency adjustments		2			4			11			—		—		—		—		—		—
Net periodic benefit cost	$	9		$	14		$	24		$	60	$	59	$	51	$	3	$	2	$	2

(a)	Relates to the Pottstown plant closure.

The estimated net loss and prior service cost for the defined benefit pension plans that will be amortized from AOCI into net periodic benefit cost over the next fiscal year are both $1 million. The estimated net loss and prior service cost for the other defined benefit postretirement plans that will be amortized from AOCI into net periodic benefit cost over the next fiscal year are $13 million and $1 million, respectively.

Additional Information

Occidental’s defined benefit pension and postretirement defined benefit plan obligations are determined based on various assumptions and discount rates. Occidental uses the fair value of assets to determine expected return on plan assets in calculating pension expense. Occidental funds and expenses negotiated pension increases for domestic union employees over the terms of the applicable collective bargaining agreements.

The following table sets forth the weighted average assumptions used to determine Occidental's benefit obligation and net periodic benefit cost for domestic plans:

	Pension Benefits		Postretirement Benefits
			Unfunded Plans		Funded Plans
For the years ended December 31,	2006	2005	2006	2005	2006	2005
Benefit Obligation Assumptions:
Discount rate	5.53%	5.33%	5.53%	5.33%	5.53%	5.33%
Rate of compensation increase	4.00%	4.00%	—	—	—	—
Net Periodic Benefit Cost Assumptions:
Discount rate	5.33%	5.50%	5.33%	5.50%	5.33%	5.50%
Assumed long term rate of return on assets	7.50%	8.00%	—	—	7.50%	8.00%
Rate of compensation increase	4.00%	4.00%	—	—	—	—

For domestic pension plans, Occidental bases the discount rate on the average yield provided by the Moody’s Aaa 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 assumed long-term rate of return on assets is estimated 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. For countries in hyperinflationary environments, real discount rates were used. The real discount rates used in these countries ranged from a low of 4.8 percent to a high of 5.5 percent at both December 31, 2006 and 2005. For countries under a more stable inflationary environment, the nominal discount rates were used in determining the benefit obligation. The nominal discount rates used ranged from a low of 3 percent to a high of 11 percent at December 31, 2006 and a low of 3 percent to a high of 6.8 percent at December 31, 2005. 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 2 percent to a high of 10 percent in 2006 and from a low of 2 percent to a high of 6 percent in 2005, 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 2006 and 2005.

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 2.5 percent and 3 percent as of December 31, 2006 and 2005 (beginning in 1993, participants other than certain union employees have paid 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 11 percent in 2006 to 6 percent through the year 2010 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 $20 million or a reduction of $19 million, respectively, in the postretirement benefit obligation as of December 31, 2006, and a corresponding increase or reduction of $1 million in interest cost in 2006. The annual service costs would not be materially affected by these changes.

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.

Asset allocations of Occidental’s defined benefit pension and funded postretirement benefit plans are as follows:

	Pension Benefits				Postretirement Benefit
					Funded Plans
As of December 31,	2006		2005		2006		2005
Asset Category:
Equity securities	56	%	60	%	55	%	58	%
Debt securities	44		40		45		42
Total	100	%	100	%	100	%	100	%

Occidental employs a total return investment approach that uses a mix of equity and fixed income investments 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 Occidental executives, 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 United States and non-United States 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.

Occidental expects to contribute $3 million to its defined benefit pension plans during 2007. All of the contributions are expected to be in the form of cash.

Estimated future benefit payments, which reflect expected future service, as appropriate, are as follows:

For the years ended December 31, (in millions)	Pension Benefits		Postretirement Benefits
2007	$	26	$	56
2008	$	27	$	55
2009	$	28	$	55
2010	$	30	$	54
2011	$	33	$	54
2012 — 2016	$	199	$	265

NOTE 14 INVESTMENTS AND RELATED-PARTY TRANSACTIONS

At December 31, 2006 and 2005, investments in unconsolidated entities comprised $498 million and $906 million of equity method investments and $294 million and $303 million of advances to equity method investees, respectively. The remainder of the 2006 investments in unconsolidated entities reflects available-for-sale securities.

EQUITY INVESTMENTS

At December 31, 2006, Occidental’s equity investments consist mainly of a 24.5-percent interest in the stock of Dolphin Energy Limited (Dolphin Energy), and various other partnerships and joint ventures, discussed below. Equity investments paid dividends of $113 million, $161 million and $91 million to Occidental in 2006, 2005 and 2004, respectively. At December 31, 2006, cumulative undistributed earnings of equity-method investees since acquisition were $104 million. At December 31, 2006, Occidental’s investments in equity investees exceeded the underlying equity in net assets by $255 million, of which $135 million represents goodwill that will not be amortized and $115 million represents intangible assets, which will be amortized over the life of the underlying assets, when placed into service.

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)	2006		2005		2004
Revenues	$	1,569	$	3,637	$	1,785
Costs and expenses		1,387		3,405		1,672
Net income	$	182	$	232	$	113
As of December 31,	2006		2005
Current assets	$	151	$	690
Non-current assets	$	812	$	2,043
Current liabilities	$	101	$	450
Long-term debt	$	562	$	1,128
Other non-current liabilities	$	26	$	600
Stockholders’ equity	$	274	$	554

Occidental’s investment in the Dolphin Project consists of two separate economic interests: a 24.5-percent undivided interest in a Development and Production Sharing Agreement, which is proportionately consolidated in the financial statements, and a 24.5-percent ownership interest in the stock of Dolphin Energy, which is accounted for as an equity investment. In July 2005, Dolphin Energy entered into a bridge loan in an amount of $2.45 billion. The proceeds of the new bridge loan were used to pay off amounts outstanding on a previous bridge loan and are being used to fund the construction of the Dolphin Project. The new bridge loan has a term of four years, is a revolving credit facility for the first two years and may be converted to a term loan thereafter. In September 2005, Dolphin Energy entered into an agreement with banks to provide a $1.0 billion Islamic-law-compliant facility to fund the construction of a certain portion of the Dolphin Project. This four-year financing facility is structured as a transaction in which Dolphin Energy constructs part of the midstream portion of the Dolphin Project on behalf of a group of Islamic investors and enters into a lease to use such assets upon construction completion. Occidental guarantees 24.5 percent of both of these obligations of Dolphin Energy. At December 31, 2006, Occidental’s portion of the bridge loan and Islamic-law-compliant facility draw downs were $469 million and $184 million, respectively. Occidental had recorded $473 million on the balance sheet at December 31, 2006, for the combined bridge loan and Islamic-law-compliant facility. The remaining amounts of the bridge loan and Islamic-law-compliant facility drawdowns are included in the guarantee amounts discussed in Note 9.

In Ecuador, Occidental has a 14-percent interest in the OCP oil export pipeline. As of December 31, 2006, Occidental’s net investment in and advances to the project totaled $72 million. Occidental reports this investment in its consolidated financial 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. In May 2006, Ecuador terminated Occidental’s contract for the operation of Block 15, which comprised all of its oil-producing operations in the country, and seized Occidental’s Block 15 assets. Occidental’s guarantee of its share of the ship-or-pay obligations provides the lenders the right to require Occidental to make an advance tariff payment as a result of the expropriation. At December 31, 2006, the total pre-tax advance tariff payment of approximately $95 million was accrued in Occidental’s consolidated financial statements and was included in the net after-tax charge of $296 million discussed in Note 2. This advance tariff would be used by the pipeline company to service or prepay project debt. At December 31, 2006, Occidental also had obligations relating to performance bonds totaling $14 million.

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. OCP and EHP are VIEs under the provisions of FIN 46. Occidental has concluded it is not the primary beneficiary of OCP or EHP and, therefore, accounts for these investments using the equity method.

ADVANCES TO EQUITY INVESTEES

In 2004, Occidental entered into a note receivable (Note) with an equity method investee. The Note bears interest at 2 percent and is due December 31, 2007. At December 31, 2006, the outstanding balance on the Note was $196 million. In 2004, Occidental converted a contribution to an equity method investee into a subordinated revolving credit agreement (Revolver). The Revolver bears interest at 18 percent and expires on December 31, 2021. At December 31, 2006, the outstanding balance on the Revolver and related accrued interest were $55 million and $1 million, respectively.

AVAILABLE-FOR-SALE SECURITIES
Lyondell

Starting 2002, when Occidental acquired an equity investment in Lyondell Chemical Company (Lyondell), two senior executives of Occidental held seats on Lyondell’s board of directors. One of Occidental’s senior executives did not stand for re-election to Lyondell’s board of directors at its annual meeting on May 4, 2006. As a result, Occidental management believes that it no longer has the ability to exercise significant influence over Lyondell’s financial and operating policies and has discontinued accruing its share of Lyondell earnings or losses under equity-method accounting. Subsequent to May 4, 2006, Occidental classified its Lyondell shares as an available-for-sale investment.

In October 2006, Occidental sold 10 million shares of Lyondell's common stock in a registered public offering for a pre-tax gain of $90 million and gross proceeds of $250 million. At December 31, 2006, Occidental owned 20.3 million Lyondell shares of common stock (8-percent ownership), with a carrying value of $519 million, and warrants to purchase an additional five million shares of Lyondell common stock. In February 2007, Occidental exercised these warrants and received approximately 700,000 shares of Lyondell stock. Following this transaction, Occidental owned approximately 21 million shares of Lyondell common stock. Occidental has no current plans to divest the remaining Lyondell shares. However, Occidental regularly reviews and analyzes its investments and other operations in order to determine how its stockholders’ interests are best served.

In 2005, Occidental sold 11 million shares of Lyondell stock for gross proceeds of approximately $300 million. This sale resulted in a 2005 pre-tax gain of $140 million.

In 2004, Lyondell acquired Millennium Chemicals Inc. by issuing additional shares of Lyondell common stock. Under SAB 51, Occidental was required to record its share of the increase in Lyondell's net equity resulting from this issuance. Occidental increased its carrying value in Lyondell and recorded a pre-tax gain of $121 million.

Premcor

Valero Energy Corp.’s (Valero) acquisition of Premcor, Inc. resulted in a $704 million pre-tax gain and the subsequent sale of all of the Valero common shares received resulted in an additional $22 million pre-tax gain in 2005.

RELATED-PARTY TRANSACTIONS

Occidental purchases power, steam and chemicals from its equity investees and sells chemicals and power to its equity investees at market-related prices. During 2006, 2005 and 2004, Occidental entered into the following related-party transactions and had the following amounts due from or to its related parties:

December 31, (in millions)	2006		2005		2004
Purchases ^(a)	$	688	$	1,275	$	1,035
Sales	$	589	$	980	$	529
Services	$	6	$	6	$	13
Advances and amounts due from	$	216	$	256	$	315
Amounts due to	$	1	$	16	$	23

(a)	In 2006, 2005 and 2004, purchases from Lyondell accounted for 38, 59 and 61 percent, respectively.

NOTE 15 INDUSTRY SEGMENTS AND GEOGRAPHIC AREAS

Occidental has identified two reportable segments through which subsidiaries and affiliates of OPC conduct Occidental's 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.

Earnings of industry segments and geographic areas generally exclude income taxes, interest income, interest expense, environmental remediation expenses, unallocated corporate expenses, discontinued operations and cumulative effect of changes in accounting principles, but include gains and losses from dispositions of segment and geographic area assets and results and other earnings from the segments’ equity investments (except as noted below).

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, an 8-percent available-for-sale investment in Lyondell, 12-percent ownership interest in Premcor (sold in 2005), a leased cogeneration facility in Taft, Louisiana, a cogeneration facility at Ingleside, Texas (consolidated in October 2006) and a common carrier oil pipeline company.

Industry Segments
In millions

	Oil and Gas			Chemical			Corporate and Other			Total
YEAR ENDED DECEMBER 31, 2006
Net sales	$	12,676	^(a)	$	4,815	^(b)	$	170		$	17,661
Pretax operating profit (loss)	$	7,239		$	901		$	(239	) ^(c)	$	7,901
Income taxes		—			—			(3,466	) ^(f)		(3,466	)
Discontinued operations, net		—			—			(253	)		(253	)
Net income (loss)	$	7,239		$	901		$	(3,958	) ^(f)	$	4,182
Unconsolidated equity investments	$	515		$	103		$	726		$	1,344
Property, plant and equipment additions, net ^(g)	$	2,721		$	251		$	33		$	3,005
Depreciation, depletion and amortization	$	1,761		$	260		$	21		$	2,042
Total assets	$	25,418		$	3,762		$	3,175		$	32,355
YEAR ENDED DECEMBER 31, 2005
Net sales	$	9,805	^(a)	$	4,641	^(b)	$	151		$	14,597
Pretax operating profit	$	5,968		$	607		$	392	^(c)	$	6,967
Income taxes		—			—			(1,927	) ^(f)		(1,927	)
Discontinued operations, net		—			—			238			238
Cumulative effect of changes in accounting principles, net		—			—			3			3
Net income (loss)	$	5,968	^(d)	$	607	^(e)	$	(1,294	) ^(f)	$	5,281
Unconsolidated equity investments	$	436		$	92		$	681		$	1,209
Property, plant and equipment additions, net ^(g)	$	2,137		$	173		$	14		$	2,324
Depreciation, depletion and amortization	$	1,151		$	251		$	20		$	1,422
Total assets	$	18,394		$	3,845		$	3,869		$	26,108
YEAR ENDED DECEMBER 31, 2004
Net sales	$	7,093	^(a)	$	3,675	^(b)	$	111		$	10,879
Pretax operating profit (loss)	$	4,021		$	414		$	(390	) ^(c)	$	4,045
Income taxes		—			—			(1,639	) ^(e,f)		(1,639	)
Discontinued operations, net		—			—			162			162
Net income (loss)	$	4,021		$	414		$	(1,867	) ^(f)	$	2,568
Unconsolidated equity investments	$	426		$	83		$	1,218		$	1,727
Property, plant and equipment additions, net ^(g)	$	1,526		$	155		$	39		$	1,720
Depreciation, depletion and amortization	$	989		$	243		$	19		$	1,251
Total assets	$	14,549		$	3,470		$	3,372		$	21,391

(See footnotes on next page)

Footnotes:

(a)	Oil sales represented approximately 80 percent, 76 percent and 76 percent of net sales for the years ended December 31, 2006, 2005 and 2004, respectively. In 2004, sales to a major oil and gas company totaled approximately 10.5 percent of consolidated net sales.
(b)	Total product sales for the chemical segment were as follows:

	Basic Chemicals	Vinyls	Performance Chemicals
Year ended December 31, 2006	48%	48%	4%
Year ended December 31, 2005	42%	50%	8%
Year ended December 31, 2004	33%	57%	10%

(c)	Includes unallocated net interest expense, administration expense, environmental remediation and other pre-tax special items noted in footnote (f) below.
(d)	Oil & Gas includes a 2005 contract settlement charge of $26 million and a hurricane insurance charge of $18 million.
(e)	Chemical includes the 2005 write-off of plants of $159 million and a hurricane insurance charge of $11 million.
(f)	Includes the following significant items affecting earnings for the years ended December 31:

Benefit (Charge) (In millions)	2006			2005			2004
CORPORATE
Pre-tax operating profit (loss)
Debt purchase expense	$	(31	)	$	(42	)	$	—
Litigation settlements		108			—			—
Trust preferred redemption charge		—			—			(11	)
Gain on sale of Lyondell shares		90			140			—
Gain on Premcor-Valero shares		—			726			—
Gain on Lyondell stock issuance		—			—			121
Equity investment impairment		—			(15	)		—
Equity investment hurricane insurance charge		—			(2	)		—
Hurricane insurance charge		—			(10	)		(15	)
	$	167		$	797		$	95
Income taxes
State tax issue charge *	$	—		$	(10	)	$	—
Settlement of federal tax issues *		—			619			47
Deferred tax write-off due to compensation program changes *		(40	)		—			—
Reversal of tax reserves *		—			335			—
Tax effect of pre-tax adjustments		(41	)		(219	)		(35	)
	$	(81	)	$	725		$	12
Discontinued operations, net *	$	(253	)	$	238		$	162
Changes in accounting principles, net *	$	—		$	3		$	—

*	Amounts shown after-tax.

(g)	Excludes acquisitions. Amounts include capitalized interest of $51 million in 2006, $26 million in 2005 and $10 million in 2004.

Geographic Areas
In millions

	Net sales ^(a)						Property, plant and equipment, net
For the years ended December 31,	2006		2005		2004		2006		2005		2004
United States	$	11,857	$	10,553	$	8,055	$	16,657	$	13,550	$	11,612
Foreign
Qatar		1,639		1,299		900		1,727		1,671		1,497
Colombia		995		829		629		304		214		207
Yemen		877		678		537		495		276		329
Oman		633		489		253		815		489		271
Libya		549		183		—		244		223		—
Argentina		527		—		—		2,993		—		—
Canada		249		276		230		29		29		36
Pakistan		198		182		171		73		92		123
United Arab Emirates		—		—		—		825		568		240
Other Foreign		137		108		104		154		59		28
Total Foreign		5,804		4,044		2,824		7,659		3,621		2,731
Total	$	17,661	$	14,597	$	10,879	$	24,316	$	17,171	$	14,343

(a)	Sales are shown by individual country based on the location of the entity making the sale.

NOTE 16 CONDENSED CONSOLIDATING FINANCIAL INFORMATION

Vintage Petroleum, LLC is the Occidental subsidiary into which Vintage merged. Payment of the Vintage Petroleum, LLC 8.25-percent senior notes due 2012 is guaranteed by OPC (Guarantor). The following condensed supplemental consolidating financial information reflects the summarized financial information of Vintage Petroleum, LLC, and its Guarantor and the Guarantor’s non-guarantor subsidiaries (in millions):

CONDENSED CONSOLIDATING BALANCE SHEET
As of December 31, 2006

Occidental
Petroleum
Corporation

Vintage
Petroleum,
LLC

Non-
Guarantor
Subsidiaries

Eliminations

Consolidated

ASSETS

Current assets

1,686

202

4,118

—

6,006

Investments in subsidiaries and unconsolidated entities

37,093

1,127

(36,897

)

1,344

Property, plant and equipment, net

4,910

19,403

—

24,316

Other non-current assets

6,530

717

22,891

(29,449

)

689

45,312

5,850

47,539

(66,346

)

32,355

LIABILITIES AND EQUITY

Current liabilities

521

166

4,037

—

4,724

Long-term debt, net

1,706

294

619

—

2,619

Other long-term liabilities

23,901

1,796

9,239

(29,449

)

5,487

Minority interest

—

341

—

341

Stockholders’ equity

19,184

3,594

33,303

(36,897

)

19,184

45,312

5,850

47,539

(66,346

)

32,355

CONDENSED CONSOLIDATING STATEMENT OF INCOME
For the year ended December 31, 2006

Occidental
Petroleum
Corporation

Vintage
Petroleum,
LLC

Non-
Guarantor
Subsidiaries

Eliminations

Consolidated

REVENUES

Net sales

—

868

16,793

—

17,661

Interest, dividends and other income

128

624

(254

)

499

128

869

17,417

(254

)

18,160

COSTS AND OTHER DEDUCTIONS

Cost of sales

—

517

7,778

—

8,295

Selling, general and administrative and other operating expenses

283

1,369

—

1,744

Interest and debt expense, net

478

(254

)

291

761

632

9,191

(254

)

10,330

Income before taxes and other items

(633

)

237

8,226

—

7,830

Provision for domestic and foreign income and other taxes

(231

)

3,611

—

3,466

Minority interest

—

111

—

111

(Income)/loss from equity investments

(4,584

)

—

(182

)

4,584

(182

)

Income from continuing operations

4,182

151

4,686

(4,584

)

4,435

Discontinued operations, net

—

(294

)

—

(253

)

NET INCOME

4,182

192

4,392

(4,584

)

4,182

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS For the year ended December 31, 2006
	Occidental Petroleum Corporation			Vintage Petroleum, LLC			Non- Guarantor Subsidiaries			Eliminations		Consolidated
CASH FLOW FROM OPERATING ACTIVITIES
Operating cash flow from continuing operations	$	(1,907	)	$	289		$	7,799		$	—	$	6,181
Operating cash flow from discontinued operations		—			74			98			—		172
Net cash provided (used) by operating activities		(1,907	)		363			7,897			—		6,353
CASH FLOW FROM INVESTING ACTIVITIES
Capital expenditures		(3	)		(225	)		(2,777	)		—		(3,005	)
Purchase of businesses, net		(2,413	)		—			(132	)		—		(2,545	)
Other investing, net		15			944			213			—		1,172
Investing cash flow from continuing operations		(2,401	)		719			(2,696	)		—		(4,378	)
Investing cash flow from discontinued operations		—			6			(11	)		—		(5	)
Net cash provided (used) by investing activities		(2,401	)		725			(2,707	)		—		(4,383	)
CASH FLOW FROM FINANCING ACTIVITIES
Proceeds from long-term debt		—			—			173			—		173
Payments on long-term debt and capital lease liabilities		(557	)		(274	)		(235	)		—		(1,066	)
Purchase of treasury stocks		(1,473	)		—			—			—		(1,473	)
Cash dividends paid		(646	)		—			—			—		(646	)
Intercompany		5,846			(810	)		(5,036	)		—		—
Other financing, net		193			—			—			—		193
Net cash provided (used) by financing activities		3,363			(1,084	)		(5,098	)		—		(2,819	)
(Decrease) Increase in cash and cash equivalents		(945	)		4			92			—		(849	)
Cash and cash equivalents — beginning of period		2,161			—			27			—		2,188
Cash and cash equivalents — end of period	$	1,216		$	4		$	119		$	—	$	1,339

NOTE 17 SUBSEQUENT EVENTS

In January 2007, Occidental sold its 50-percent interest in the Russian Vanyoganneft joint venture to TNK-BP for approximately $485 million. At December 31, 2006, Occidental's net proved Vanyoganneft reserves were an estimated 33 million BOE (unaudited) and its net production was approximately 27,000 BOE per day in 2006. Occidental recorded a gain of approximately $400 million resulting from the sale in the first quarter of 2007.

Since December 31, 2006, Occidental has resolved certain legal disputes that it expects will result in a gain of approximately $108 million in the first quarter of 2007.

NOTE 18 COSTS AND RESULTS OF OIL AND GAS PRODUCING ACTIVITIES

In May 2006, Ecuador terminated Occidental’s contract for the operation of Block 15, which comprised all of its oil-producing operations in the country, and seized Occidental’s Block 15 assets. As a result of the seizure, Occidental has classified its Block 15 operations as discontinued operations on a retrospective basis and excluded them from all tables in Note 18.

Capitalized costs relating to oil and gas producing activities and related accumulated DD&A were as follows:

	Consolidated Subsidiaries
In millions	United States			Latin America			Middle East/ North Africa			Other Eastern Hemisphere			Total			Other Interests		^(c)
DECEMBER 31, 2006
Proved properties	$	17,085		$	3,493		$	6,395		$	259		$	27,232		$	76
Unproved properties ^(a)		802			655			265			37			1,759			1
Total property costs		17,887			4,148			6,660			296			28,991			77
Support facilities		890			95			148			106			1,239			19
Total capitalized costs ^(b)		18,777			4,243			6,808			402			30,230			96
Accumulated depreciation, depletion and amortization ^(d)		(5,217	)		(888	)		(2,701	)		(293	)		(9,099	)		(36	)
Net capitalized costs	$	13,560		$	3,355		$	4,107		$	109		$	21,131		$	60
DECEMBER 31, 2005
Proved properties	$	13,756		$	791		$	4,923		$	247		$	19,717		$	47
Unproved properties ^(a)		475			—			385			36			896			—
Total property costs		14,231			791			5,308			283			20,613			47
Support facilities		700			36			109			103			948			17
Total capitalized costs ^(b)		14,931			827			5,417			386			21,561			64
Accumulated depreciation, depletion and amortization ^(d)		(4,292	)		(613	)		(2,189	)		(259	)		(7,353	)		(26	)
Net capitalized costs	$	10,639		$	214		$	3,228		$	127		$	14,208		$	38
DECEMBER 31, 2004
Proved properties	$	11,480		$	730		$	4,048		$	256		$	16,514		$	32
Unproved properties ^(a)		457			1			18			—			476			—
Total property costs		11,937			731			4,066			256			16,990			32
Support facilities		500			42			100			86			728			15
Total capitalized costs ^(b)		12,437			773			4,166			342			17,718			47
Accumulated depreciation, depletion and amortization ^(d)		(3,553	)		(565	)		(1,829	)		(217	)		(6,164	)		(13	)
Net capitalized costs	$	8,884		$	208		$	2,337		$	125		$	11,554		$	34

(a)	The 2006 amount primarily consists of additions in Argentina, California and Yemen from the Vintage acquisition as well as existing unproved properties in California, Libya and Oman. The 2005 amount primarily consists of California, Libya and Oman. The 2004 amount consists of California and Oman.
(b)	Includes costs related to leases, exploration costs, lease and well equipment, pipelines and terminals, gas plant, other equipment and capitalized interest.
(c)	Includes capitalized costs for equity investees in Russia (sold in January 2007) and Yemen, partially offset by minority interests in a Colombian affiliate.
(d)	Includes accumulated valuation allowance for unproved properties of $108 million in 2006, $108 million in 2005 and $28 million in 2004.

Costs incurred in oil and gas property acquisition, exploration and development activities, whether capitalized or expensed, were as follows:

	Consolidated Subsidiaries
In millions	United States		Latin America		Middle East/ North Africa		Other Eastern Hemisphere		Total		Other Interests		^(a)
FOR THE YEAR ENDED DECEMBER 31,2006
Property Acquisition Costs ^(b)
Proved Properties	$	2,094	$	2,408	$	397	$	—	$	4,899	$	—
Unproved Properties		377		655		107		3		1,142		—
Exploration costs		40		61		177		37		315		1
Development costs ^(c)		1,344		320		792		14		2,470		32
Costs Incurred ^(d)	$	3,855	$	3,444	$	1,473	$	54	$	8,826	$	33
FOR THE YEAR ENDED DECEMBER 31, 2005
Property Acquisition Costs
Proved Properties	$	1,744	$	—	$	38	$	—	$	1,782	$	—
Unproved Properties		51		—		343		4		398		—
Exploration costs		39		56		47		102		244		(2	)
Development costs ^(c)		942		56		834		14		1,846		15
Costs Incurred ^(d)	$	2,776	$	112	$	1,262	$	120	$	4,270	$	13
FOR THE YEAR ENDED DECEMBER 31, 2004
Property Acquisition Costs
Proved Properties	$	43	$	94	$	21	$	—	$	158	$	(12	)
Unproved Properties		4		—		—		4		8		—
Exploration costs		31		26		28		52		137		—
Development costs ^(c)		581		54		715		11		1,361		10
Costs Incurred ^(d)	$	659	$	174	$	764	$	67	$	1,664	$	(2	)

(a)	Includes equity investees’ costs in Russia (sold in January 2007) and Yemen, partially offset by minority interests in a Colombian affiliate.
(b)	Includes acquisition costs and related step-up for deferred income taxes of $1.34 billion for the purchase of Vintage. There was no goodwill recorded for this transaction.
(c)	Includes asset retirement costs of $76 million in 2006, $12 million in 2005 and $25 million in 2004.
(d)	Excludes capitalized CO2 of $64 million in 2006, $59 million in 2005 and $54 million in 2004.

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
In millions	United States		Latin America		Middle East/ North Africa			Other Eastern Hemisphere		Total		Other Interests		^(a)
FOR THE YEAR ENDED DECEMBER 31, 2006
Revenues ^(b)	$	7,066	$	1,358	$	3,659	^(d)	$	173	$	12,256	$	223	^(d)
Production costs		1,717		280		351			17		2,365		149
Exploration expenses		88		32		140			35		295		1
Other operating expenses		410		47		121			22		600		8
Depreciation, depletion and amortization		926		275		525			35		1,761		10
Pretax income		3,925		724		2,522			64		7,235		55
Income tax expense^(c)		1,151		310		1,424	^(d)		26		2,911		11	^(d)
Results of operations	$	2,774	$	414	$	1,098		$	38	$	4,324	$	44
FOR THE YEAR ENDED DECEMBER 31, 2005
Revenues ^(b)	$	6,000	$	666	$	2,633	^(d)	$	159	$	9,458	$	286	^(d)
Production costs		1,311		74		207			15		1,607		203
Exploration expenses		132		53		56			72		313		(2	)
Other operating expenses		291		6		112			13		422		7
Depreciation, depletion and amortization		706		55		347			42		1,150		11
Pretax income		3,560		478		1,911			17		5,966		67
Income tax expense^(c)		982		224		1,028	^(d)		16		2,250		3	^(d)
Results of operations	$	2,578	$	254	$	883		$	1	$	3,716	$	64
FOR THE YEAR ENDED DECEMBER 31, 2004
Revenues ^(b)	$	4,467	$	505	$	1,690	^(d)	$	149	$	6,811	$	200	^(d)
Production costs		1,016		70		175			16		1,277		122
Exploration expenses		117		22		20			49		208		1
Other operating expenses		226		15		77			16		334		6
Depreciation, depletion and amortization		622		44		276			46		988		12
Pretax income		2,486		354		1,142			22		4,004		59
Income tax expense^(c)		689		179		525	^(d)		14		1,407		9	^(d)
Results of operations	$	1,797	$	175	$	617		$	8	$	2,597	$	50

(a)	Includes results of operations for equity investees in Russia (sold in January 2007) and Yemen, partially offset by minority interests in a Colombian affiliate.
(b)	Revenues from net production exclude royalty payments and other adjustments.
(c)	United States federal income taxes reflect certain expenses related to oil and gas activities allocated for United States income tax purposes only, including allocated interest and corporate overhead. Foreign income taxes were included in geographic areas on the basis of operating results.
(d)	Revenues and income tax expense include taxes owed by Occidental but paid by governmental entities on its behalf.

Results per Unit of Production (Unaudited)

	Consolidated Subsidiaries
	United States		Latin America		Middle East/ North Africa			Other Eastern Hemisphere		Total		Other Interests		^(a)
FOR THE YEAR ENDED DECEMBER 31, 2006
Revenues from net production
Oil ($/bbl.)	$	58.13	$	51.57	$	61.43	^(b)	$	56.56	$	57.87	$	34.25	^(b)
Natural gas ($/Mcf)	$	6.51	$	1.99	$	0.97		$	2.94	$	5.70	$	0.14
Barrel of oil equivalent ($/bbl.)^(c,d)	$	52.78	$	48.63	$	59.40	^(b)	$	27.62	$	52.83	$	29.75	^(b)
Production costs		12.83		10.02		8.22			2.76		11.23		15.40
Exploration expenses		0.66		1.15		3.27			5.65		1.40		0.19
Other operating expenses		3.06		1.69		2.84			3.47		2.85		0.86
Depreciation, depletion and amortization		6.91		9.84		12.30			5.52		8.35		2.30
Pretax income		29.32		25.93		32.77			10.22		29.00		11.00
Income tax expense ^(e)		8.60		11.11		7.06	^(b)		4.11		8.49		2.49	^(b)
Results of operations	$	20.72	$	14.82	$	25.71		$	6.11	$	20.51	$	8.51
FOR THE YEAR ENDED DECEMBER 31, 2005
Revenues from net production
Oil ($/bbl.)	$	50.80	$	51.20	$	49.77	^(b)	$	46.75	$	50.50	$	34.75	^(b)
Natural gas ($/Mcf)	$	7.11	$	—	$	1.52		$	2.44	$	6.21	$	0.16
Barrel of oil equivalent ($/bbl.)^(c,d)	$	47.80	$	51.20	$	46.77	^(b)	$	24.04	$	46.97	$	33.28	^(b)
Production costs		10.44		5.69		5.54			2.27		8.81		19.76
Exploration expenses		1.05		4.07		1.50			10.89		1.72		—
Other operating expenses		2.32		0.46		3.00			1.97		2.31		0.75
Depreciation, depletion and amortization		5.62		4.23		9.30			6.35		6.30		1.77
Pretax income		28.37		36.75		27.43			2.56		27.83		11.00
Income tax expense ^(e)		7.82		17.21		3.78	^(b)		2.42		7.47		1.86	^(b)
Results of operations	$	20.55	$	19.54	$	23.65		$	0.14	$	20.36	$	9.14
FOR THE YEAR ENDED DECEMBER 31, 2004
Revenues from net production
Oil ($/bbl.)	$	37.72	$	36.99	$	34.88	^(b)	$	33.13	$	36.82	$	23.94	^(b)
Natural gas ($/Mcf)	$	5.35	$	—	$	0.97		$	2.25	$	4.60	$	—
Barrel of oil equivalent ($/bbl.)^(c,d)	$	35.97	$	36.99	$	32.16	^(b)	$	20.63	$	34.68	$	23.94	^(b)
Production costs		8.18		5.13		4.83			2.21		7.04		12.11
Exploration expenses		0.94		1.61		0.55			6.78		1.15		0.09
Other operating expenses		1.82		1.10		2.13			2.21		1.84		0.83
Depreciation, depletion and amortization		5.01		3.22		7.62			6.37		5.45		1.66
Pretax income		20.02		25.93		17.03			3.06		19.20		9.25
Income tax expense ^(e)		5.55		13.11		—			1.94		4.87		2.40	^(b)
Results of operations	$	14.47	$	12.82	$	17.03		$	1.12	$	14.33	$	6.85

(a)	Includes results of operations for equity investees in Russia (sold in January 2007) and Yemen.
(b)	Revenues and income tax expense exclude taxes owed by Occidental but paid by governmental entities on its behalf.
(c)	Natural gas volumes have been converted to equivalent barrels based on energy content of six Mcf of gas to one barrel of oil.
(d)	Revenues from net production exclude royalty payments and other adjustments.
(e)	United States federal income taxes reflect certain expenses related to oil and gas activities allocated for United States income tax purposes only, including allocated interest and corporate overhead. Foreign income taxes were included in geographic areas on the basis of operating results.

2006 Quarterly Financial Data (Unaudited)
In millions, except per-share amounts

Occidental Petroleum Corporation
and Subsidiaries

Three months ended

March 31

June 30

September 30

December 31

Segment net sales

Oil and gas

3,125

3,292

3,207

3,052

Chemical

1,241

1,273

1,265

1,036

Other

Net sales

4,396

4,599

4,522

4,144

Gross profit

2,457

2,465

2,424

2,021

Segment earnings

Oil and gas

1,910

1,953

1,877

1,499

Chemical

248

250

247

156

2,158

2,203

2,124

1,655

Unallocated corporate items

Interest expense, net

(29

)

(33

)

(18

)

(51

)

Income taxes

(905

)

(882

)

(885

)

(794

)

Other

(73

)

(84

)

(62

)

111

Income from continuing operations

1,151

1,204

1,159

921

Discontinued operations, net

(347

)

Net income

1,229

857

1,168

928

Basic earnings per common share

Income from continuing operations

1.36

1.40

1.36

1.09

Discontinued operations, net

0.09

(0.40

)

0.01

Basic earnings per common share

1.45

1.00

1.37

1.10

Diluted earnings per common share

Income from continuing operations

1.34

1.39

1.35

1.08

Discontinued operations, net

0.09

(0.40

)

0.01

Diluted earnings per common share

1.43

0.99

1.36

1.09

Dividends per common share

0.18

0.22

Market price per common share

High

49.00

54.26

55.45

52.40

Low

40.94

44.78

44.01

43.75

2005 Quarterly Financial Data (Unaudited)
In millions, except per-share amounts

Occidental Petroleum Corporation
and Subsidiaries

Three months ended	March 31			June 30			September 30			December 31
Segment net sales
Oil and gas	$	2,089		$	2,220		$	2,617		$	2,879
Chemical		1,061			1,128			1,190			1,262
Other		23			37			50			41
Net sales	$	3,173		$	3,385		$	3,857		$	4,182
Gross profit	$	1,675		$	1,797		$	2,066		$	2,251
Segment earnings
Oil and gas	$	1,279		$	1,255		$	1,638		$	1,796
Chemical		214			225			3			165
		1,493			1,480			1,641			1,961
Unallocated corporate items
Interest expense, net		(61	)		(47	)		(70	)		(23	)
Income taxes		(584	)		(26	)		(574	)		(743	)
Other		(51	)		73			660			(89	)
Income from continuing operations		797			1,480			1,657			1,106
Discontinued operations, net		49			56			87			46
Cumulative effect of changes in accounting principles		—			—			3			—
Net income	$	846		$	1,536		$	1,747		$	1,152
Basic earnings per common share
Income from continuing operations	$	1.00		$	1.84		$	2.05		$	1.36
Discontinued operations, net		0.06			0.07			0.11			0.06
Basic earnings per common share	$	1.06		$	1.91		$	2.16		$	1.42
Diluted earnings per common share
Income from continuing operations	$	0.98		$	1.82		$	2.01		$	1.34
Discontinued operations, net		0.06			0.07			0.11			0.06
Diluted earnings per common share	$	1.04		$	1.89		$	2.12		$	1.40
Dividends per common share	$	0.155		$	0.155		$	0.155		$	0.18
Market price per common share
High	$	37.45		$	40.50		$	44.90		$	43.43
Low	$	27.09		$	32.03		$	38.74		$	34.40

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 include condensate. The reserves are stated after applicable royalties. These estimates include reserves in which Occidental holds an economic interest under PSCs 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 senior corporate officer of Occidental is responsible for the internal audit and review of its oil and gas reserves data. In addition, a Corporate Reserves Review Committee (the Reserves Committee) has been established, consisting of senior corporate officers, to monitor and review Occidental's oil and gas reserves. The Reserves Committee reports to the Audit Committee of Occidental's Board of Directors periodically throughout the year. Occidental has retained Ryder Scott Company, L.P. (Ryder Scott), independent petroleum engineering consultants, to review its annual oil and gas reserve estimation processes since 2004.

Based on this review, including the data, technical processes and interpretations presented by Occidental, Ryder Scott has concluded that the methodologies used by Occidental in preparing the relevant estimates generally comply with current SEC standards. Ryder Scott has not been engaged to render an opinion as to the reserves volumes reported by Occidental.

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.

In May 2006, Ecuador terminated Occidental’s contract for the operation of Block 15, which comprised all of its oil-producing operations in the country, and seized Occidental’s Block 15 assets. As a result of this seizure, Occidental has classified its Block 15 operations as discontinued operations on a retrospective basis and excluded them from all tables in the Supplemental Oil and Gas Information section.

Oil Reserves
In millions of barrels

	Consolidated Subsidiaries
	United States		Latin America		Middle East/ North Africa		Other Eastern Hemisphere		Total		Other Interests	^(b)
PROVED DEVELOPED AND UNDEVELOPED RESERVES
Balance at December 31, 2003	1,500		46		326	^(a)	12		1,884		48
Revisions of previous estimates	(4	)	(1	)	16		(3	)	8		5
Improved recovery	72		6		10		—		88		1
Extensions and discoveries	9		—		3		—		12		2
Purchases of proved reserves	10		29		—		—		39		(4	)
Production	(93	)	(13	)	(33	)	(3	)	(142	)	(9	)
Balance at December 31, 2004	1,494		67		322	^(a)	6		1,889		43
Revisions of previous estimates	29		(13	)	(34	)	—		(18	)	8
Improved recovery	98		6		3		—		107		—
Extensions and discoveries	7		3		36		—		46		1
Purchases of proved reserves	108		—		4		—		112		—
Sales of proved reserves	(8	)	—		—		—		(8	)	—
Production	(92	)	(13	)	(35	)	(2	)	(142	)	(7	)
Balance at December 31, 2005	1,636		50		296	^(a)	4		1,986		45
Revisions of previous estimates	(28	)	10		39		1		22		(7	)
Improved recovery	71		33		14		—		118		(1	)
Extensions and discoveries	3		7		14		—		24		—
Purchases of proved reserves	98		152		4		—		254		—
Sales of proved reserves	(4	)	—		—		—		(4	)	—
Production	(98	)	(26	)	(40	)	(2	)	(166	)	(7	)
Balance at December 31, 2006	1,678		226		327	^(a)	3		2,234		30
PROVED DEVELOPED RESERVES ^(c)
December 31, 2003	1,262		43		227		11		1,543		35
December 31, 2004	1,260		65		208		6		1,539		37
December 31, 2005	1,336		44		174		4		1,558		37
December 31, 2006	1,396		140		249		3		1,788		23

(a)	All Middle East/North Africa amounts are related to PSCs, and do not include amounts related to taxes owed by Occidental but paid by governmental entities on its behalf.
(b)	Includes reserves applicable to equity investees in Russia (sold in January 2007) and Yemen, partially offset by minority interests in a Colombian affiliate.
(c)	Approximately four percent of the proved developed reserves at December 31, 2006 are nonproducing. Over half of these reserves are located in Latin America and the remainder is in the United States and Middle East/North Africa. Plans are to begin producing these reserves in 2007.

Gas Reserves
In billions of cubic feet

	Consolidated Subsidiaries
	United States		Latin America		Middle East/ North Africa		Other Eastern Hemisphere		Total		Other Interests
PROVED DEVELOPED AND UNDEVELOPED RESERVES
Balance at December 31, 2003	1,826		—		654	^(a)	105		2,585		9
Revisions of previous estimates	94		—		134		13		241		(9	)
Improved recovery	180		—		—		5		185		—
Extensions and discoveries	181		—		—		10		191		—
Purchases of proved reserves	7		—		—		—		7		—
Sales of proved reserves	(1	)	—		—		—		(1	)	—
Production	(186	)	—		(20	)	(27	)	(233	)	—
Balance at December 31, 2004	2,101		—		768	^(a)	106		2,975		—
Revisions of previous estimates	53		—		(32	)	9		30		6
Improved recovery	129		—		—		2		131		—
Extensions and discoveries	96		—		331		—		427		—
Purchases of proved reserves	164		—		—		—		164		—
Sales of proved reserves	(3	)	—		—		—		(3	)	—
Production	(202	)	—		(16	)	(28	)	(246	)	(6	)
Balance at December 31, 2005	2,338		—		1,051	^(a)	89		3,478		—
Revisions of previous estimates	(132	)	45		59		—		(28	)	8
Improved recovery	123		—		7		6		136		—
Extensions and discoveries	58		—		—		1		59		—
Purchases of proved reserves	274		161		—		—		435		—
Sales of proved reserves	(2	)	—		—		—		(2	)	—
Production	(217	)	(12	)	(11	)	(28	)	(268	)	(8	)
Balance at December 31, 2006	2,442		194		1,106	^(a)	68		3,810		—
PROVED DEVELOPED RESERVES ^(b)
December 31, 2003	1,618		—		91		94		1,803		9
December 31, 2004	1,644		—		100		95		1,839		—
December 31, 2005	1,846		—		73		80		1,999		—
December 31, 2006	1,953		137		560		68		2,718		—

(a)	All Middle East/North Africa amounts are related to PSCs, and do not include amounts related to taxes owed by Occidental but paid by governmental entities on its behalf.
(b)	Approximately twenty-two percent of the proved developed reserves at December 31, 2006 are nonproducing. Plans are to begin producing these reserves in 2007.

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, 2006, 2005 and 2004. 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 2006, 2005 and 2004 disclosures, the West Texas Intermediate oil prices used were $61.05 per barrel, $61.04 per barrel and $43.45 per barrel, respectively. The Henry Hub gas prices used for the 2006, 2005 and 2004 disclosures were $5.64/MMBtu, $10.08/MMBtu and $6.03/MMBtu, respectively.

Standardized Measure of Discounted Future Net Cash Flows
In millions

	Consolidated Subsidiaries
	United States			Latin America			Middle East/ North Africa			Other Eastern Hemisphere			Total			Other Interests		^(a)
AT DECEMBER 31, 2006
Future cash flows	$	102,873		$	9,279		$	18,436		$	346		$	130,934		$	1,139
Future costs
Production costs and other operating expenses		(49,797	)		(3,002	)		(4,676	)		(129	)		(57,604	)		(1,301	)
Development costs ^(b)		(4,274	)		(1,213	)		(1,359	)		(13	)		(6,859	)		(85	)
Future net cash flows before income taxes		48,802			5,064			12,401			204			66,471			(247	)
Future income tax expense		(16,451	)		(1,778	)		(325	)		(99	)		(18,653	)		44
Future net cash flows		32,351			3,286			12,076			105			47,818			(203	)
Ten percent discount factor		(17,579	)		(1,178	)		(4,441	)		(10	)		(23,208	)		(54	)
Standardized measure	$	14,772		$	2,108		$	7,635		$	95		$	24,610		$	(257	)
AT DECEMBER 31, 2005
Future cash flows	$	105,307		$	2,675		$	15,574		$	441		$	123,997		$	1,695
Future costs
Production costs and other operating expenses		(43,772	)		(830	)		(3,559	)		(111	)		(48,272	)		(1,317	)
Development costs ^(b)		(3,224	)		(86	)		(1,096	)		(23	)		(4,429	)		(118	)
Future net cash flows before income taxes		58,311			1,759			10,919			307			71,296			260
Future income tax expense		(19,509	)		(880	)		—			(102	)		(20,491	)		(8	)
Future net cash flows		38,802			879			10,919			205			50,805			252
Ten percent discount factor		(21,608	)		(223	)		(4,463	)		(36	)		(26,330	)		(53	)
Standardized measure	$	17,194		$	656		$	6,456		$	169		$	24,475		$	199
AT DECEMBER 31, 2004
Future cash flows	$	67,273		$	2,478		$	12,042		$	438		$	82,231		$	959
Future costs
Production costs and other operating expenses		(28,518	)		(1,099	)		(3,236	)		(147	)		(33,000	)		(633	)
Development costs ^(b)		(2,214	)		(63	)		(1,421	)		(30	)		(3,728	)		(55	)
Future net cash flows before income taxes		36,541			1,316			7,385			261			45,503			271
Future income tax expense		(11,751	)		(547	)		—			(89	)		(12,387	)		40
Future net cash flows		24,790			769			7,385			172			33,116			311
Ten percent discount factor		(14,104	)		(192	)		(3,389	)		(27	)		(17,712	)		(59	)
Standardized measure	$	10,686		$	577		$	3,996		$	145		$	15,404		$	252

(a)	Includes future net cash flows applicable to equity investees in Russia (sold in January 2007) and Yemen, partially offset by minority interests in a Colombian affiliate.
(b)	Includes dismantlement and abandonment costs.

Changes in the Standardized Measure of Discounted Future
Net Cash Flows From Proved Reserve Quantities
In millions

For the years ended December 31,	2006			2005			2004
Beginning of year	$	24,475		$	15,404		$	12,160
Sales and transfers of oil and gas produced, net of production costs and other operating expenses		(8,758	)		(6,804	)		(5,007	)
Net change in prices received per barrel, net of production costs and other operating expenses		(3,511	)		13,373			5,796
Extensions, discoveries and improved recovery, net of future production and development costs		2,723			3,024			1,763
Change in estimated future development costs		(2,596	)		(1,568	)		(960	)
Revisions of quantity estimates		1,285			(1,129	)		142
Development costs incurred during the period		2,465			1,824			1,332
Accretion of discount		3,232			1,983			1,579
Net change in income taxes		357			(3,950	)		(795	)
Purchases and sales of reserves in place, net		4,186			2,041			565
Changes in production rates and other		752			277			(1,171	)
Net change		135			9,071			3,244
End of year	$	24,610		$	24,475		$	15,404

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, 2006, 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
	United States		Latin America		^(a)	Middle East/ North Africa			Other Eastern Hemisphere		^(a)	Total		Other Interests		^(c)
2006
Oil — Average sales price ($/bbl.)	$	58.13	$	52.40		$	61.58	^(d)	$	56.70		$	57.95	$	34.25
Gas — Average sales price ($/Mcf)	$	6.51	$	2.00		$	0.97		$	2.94		$	5.66	$	0.14
Average oil and gas production cost ($/bbl.) ^(b)	$	12.83	$	10.02		$	8.22		$	2.76		$	11.23	$	15.40
2005
Oil — Average sales price ($/bbl.)	$	50.21	$	51.18		$	49.88	^(d)	$	46.84		$	50.19	$	36.16
Gas — Average sales price ($/Mcf)	$	7.11	$	—		$	0.96		$	2.44		$	6.11	$	0.16
Average oil and gas production cost ($/bbl.) ^(b)	$	10.44	$	5.69		$	5.54		$	2.27		$	8.81	$	19.76
2004
Oil — Average sales price ($/bbl.)	$	37.72	$	36.85		$	34.88	^(d)	$	33.13		$	36.79	$	23.83
Gas — Average sales price ($/Mcf)	$	5.35	$	—		$	0.97		$	2.25		$	4.56	$	—
Average oil and gas production cost ($/bbl.) ^(b)	$	8.18	$	5.13		$	4.83		$	2.21		$	7.04	$	12.11

(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 (sold in January 2007) and Yemen.
(d)	Excludes taxes owed by Occidental but paid by governmental entities on its behalf.

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, 2006, Occidental’s net productive and dry–exploratory and development wells completed.

			Consolidated Subsidiaries
			United States	Latin America	Middle East/ North Africa	Other Eastern Hemisphere	Total	Other Interests	^(a)
2006
Oil	—	Exploratory	0.5	11.0	2.4	0.2	14.1	—
		Development	437.9	173.9	75.6	1.5	688.9	(1.4	)
Gas	—	Exploratory	—	—	2.1	0.8	2.9	—
		Development	124.7	—	—	1.5	126.2	—
Dry	—	Exploratory	5.0	0.4	2.3	0.3	8.0	0.4
		Development	21.5	4.0	3.7	0.5	29.7	—
2005
Oil	—	Exploratory	1.5	1.6	4.7	0.2	8.0	(0.3	)
		Development	374.4	20.2	102.6	2.3	499.5	(0.1	)
Gas	—	Exploratory	—	—	—	—	—	—
		Development	104.3	—	—	0.8	105.1	—
Dry	—	Exploratory	2.8	2.0	2.9	1.5	9.2	(0.4	)
		Development	13.1	1.0	4.9	—	19.0	—
2004
Oil	—	Exploratory	2.8	—	3.7	—	6.5	—
		Development	345.9	13.0	66.4	0.4	425.7	5.0
Gas	—	Exploratory	1.4	—	0.7	1.0	3.1	—
		Development	36.7	—	2.6	2.2	41.5	—
Dry	—	Exploratory	2.6	0.5	1.1	2.5	6.7	—
		Development	9.0	1.0	—	0.3	10.3	(0.1	)

(a)	Includes amounts applicable to equity investees in Russia (sold in January 2007) 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, 2006, Occidental’s productive oil and gas wells (both producing and capable of production). The numbers in parentheses indicate the number of wells with multiple completions.

Consolidated Subsidiaries

Wells at December 31, 2006

United
States

Latin
America

Middle
East/
North Africa

Other
Eastern
Hemisphere

Total

Other
Interests

^(c)

Oil

—

Gross ^(a)

21,698

(675)

2,640

(2,283)

1,201

(31)

(—)

25,597

(2,989)

442

(50)

Net ^(b)

15,796

(479)

2,222

(2,031)

582

(24)

(—)

18,626

(2,534)

195

(25)

Gas

—

Gross ^(a)

3,181

(208)

190

(161)

(2)

(—)

3,435

(371)

(—)

Net ^(b)

2,712

(149)

188

(161)

(2)

(—)

2,937

(312)

(—)

(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 (sold in January 2007) and Yemen, partially offset by minority interests in a Colombian affiliate.

Participation in Exploratory and Development Wells Being Drilled

The following table sets forth, as of December 31, 2006, Occidental’s participation in exploratory and development wells being drilled.

			Consolidated Subsidiaries
Wells at December 31, 2006			United States	Latin America	Middle East/ North Africa	Other Eastern Hemisphere	Total	Other Interests	^(a)
Exploratory and development wells
	—	Gross	56	9	41	—	106	2
	—	Net	39	9	15	—	63	1

(a)	Includes amounts applicable to equity investees in Russia (sold in January 2007) and Yemen, partially offset by minority interests in a Colombian affiliate.

At December 31, 2006, Occidental was participating in 107 pressure maintenance projects in the United States, 24 in Latin America, 29 in the Middle East/North Africa and 7 in the Other Eastern Hemisphere.

Oil and Gas Acreage

The following table sets forth, as of December 31, 2006, Occidental’s holdings of developed and undeveloped oil and gas acreage.

Consolidated Subsidiaries

Thousands of acres at
December 31, 2006

United
States

Latin
America

Middle
East/
North Africa

Other
Eastern
Hemisphere

Total

Other
Interests

^(e)

Developed ^(a)

—

Gross ^(b)

4,597

576

936

1,183

7,292

114

—

Net ^(c)

3,097

498

449

269

4,313

Undeveloped ^(d)

—

Gross ^(b)

1,687

25,333

34,695

9,278

70,993

—

Net ^(c)

1,118

14,512

25,027

3,681

44,338

(444

)

(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 PSCs 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 (sold in January 2007) and Yemen, partially offset by minority interests in a Colombian affiliate.

Oil and Natural Gas Production Per Day

The following table sets forth, for each of the three years in the period ended December 31, 2006, Occidental’s oil, NGLs and natural gas production per day.

	2006		2005		2004
United States
Crude oil and liquids (MBBL)
California	86		76		78
Permian	167		161		154
Horn Mountain	12		13		19
Hugoton and other	3		3		3
TOTAL	268		253		254
Natural Gas (MMCF)
California	256		242		237
Hugoton and other	138		133		127
Permian	194		170		130
Horn Mountain	7		8		13
TOTAL	595		553		507
Latin America
Crude oil (MBBL)
Argentina	33		—		—
Colombia	38		36		37
TOTAL	71		36		37
Natural Gas (MMCF)
Argentina	17		—		—
Bolivia	17		—		—
TOTAL	34		—		—
Middle East/North Africa
Crude oil (MBBL)
Oman	18		17		13
Qatar	43		42		45
Yemen	29		28		32
Libya	23		8		—
TOTAL	113		95		90
Natural Gas (MMCF)
Oman	30		44		55
Other Eastern Hemisphere
Crude oil (MBBL)
Pakistan	4		5		7
Natural Gas (MMCF)
Pakistan	76		77		75
Barrels of Oil Equivalent (MBOE) ^(a)
Subtotal consolidated subsidiaries	578		501		494
Colombia – minority interest	(5	)	(4	)	(4	)
Russia – Occidental net interest ^(b)	27		28		29
Yemen – Occidental net interest	1		1		1
Total worldwide production ^(c)	601		526		520

(a)	Natural gas volumes have been converted to equivalent BOE based on energy content of 6,000 cubic feet (one thousand cubic feet is referred to as a “Mcf”) of gas to one barrel of oil.
(b)	Sold in January 2007.
(c)	Occidental has classified its Ecuador Block 15 operations as discontinued operations on a retrospective application basis and excluded them from this table. Excluded production from the Block 15 operations averaged 43,000 BOE per day for the first five months of 2006, 42,000 BOE per day in 2005 and 46,000 BOE per day in 2004.

Schedule II – Valuation and Qualifying Accounts
In millions

Occidental Petroleum Corporation
and Subsidiaries

			Additions
	Balance at Beginning of Period		Charged to Costs and Expenses		Charged to Other Accounts			Deductions			Balance at End of Period
2006
Allowance for doubtful accounts	$	27	$	—	$	5		$	(17	)	$	15
Environmental	$	418	$	48	$	17	^(a)	$	(71	)^(b)	$	412
Foreign and other taxes, litigation and other reserves		227		20		100	^(c)		(24	)		323
	$	645	$	68	$	117		$	(95	)	$	735	^(d)
2005
Allowance for doubtful accounts	$	27	$	—	$	—		$	—		$	27
Environmental	$	375	$	63	$	51	^(a)	$	(71	)^(b)	$	418
Foreign and other taxes, litigation and other reserves		1,061		43		11			(888	)^(e)		227
	$	1,436	$	106	$	62		$	(959	)	$	645	^(d)
2004
Allowance for doubtful accounts	$	24	$	3	$	—		$	—		$	27
Environmental	$	372	$	60	$	6		$	(63	)^(b)	$	375
Foreign and other taxes, litigation and other reserves		1,153		34		—			(126	)^(f)		1,061
	$	1,525	$	94	$	6		$	(189	)	$	1,436	^(d)

(a)	Primarily represents acquisitions.
(b)	Primarily represents payments.
(c)	Primarily represents acquisitions and balance sheet reclassifications.
(d)	Of these amounts, $139 million, $138 million and $154 million in 2006, 2005 and 2004, respectively, are classified as current.
(e)	Includes reversal of tax reserves of $874 million.
(f)	Primarily represents balance sheet reclassifications.

ITEM 9 CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

Not applicable.

ITEM 9A CONTROLS AND PROCEDURES
DISCLOSURE 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 were effective as of December 31, 2006.

There has been no change in Occidental's internal control over financial reporting during the fourth quarter of 2006 that has materially affected, or is reasonably likely to materially affect, Occidental's internal control over financial reporting. Management’s Annual Assessment of and Report on Occidental’s Internal Control over Financial Reporting and the Report of Independent Registered Public Accounting Firm on Internal Control over Financial Reporting, set forth in Item 8, are incorporated by reference herein.

Part III
ITEM 10 DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

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 Occidental's directors, its employees and the employees of entities it controls. The Code is posted on the Occidental website www.oxy.com. Occidental will satisfy any disclosure requirement under Item 5.05 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" and “Nominations for Directors for Term Expiring in 2008” in Occidental's definitive proxy statement filed in connection with its May 4, 2007, Annual Meeting of Stockholders (2007 Proxy Statement). See also the list of Occidental's executive officers and significant employees and related information under "Executive Officers" in Part I of this report.

ITEM 11 EXECUTIVE COMPENSATION

This item incorporates by reference the information appearing under the captions "Executive Compensation" and "Election of Directors — Information Regarding the Board of Directors and Its Committees" in the 2007 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 2007 Proxy Statement.

ITEM 13 CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

This item incorporates by reference the information appearing under the caption “Election of Directors – Information Regarding the Board of Directors and its Committees – Independence” in the 2007 Proxy Statement.

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 2007 Proxy Statement.

Part IV
ITEM 15 EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(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

2.1*	Agreement and Plan of Merger among Occidental Petroleum Corporation, Occidental Transaction 1, LLC and Vintage Petroleum, Inc., dated as of October 13, 2005. (Disclosure schedules to this agreement have been omitted pursuant to Item 601(b)(2) of Regulation S-K) (filed as Exhibit 2.1 to Occidental's Current Report on Form 8-K dated October 13, 2005 (filed October 17, 2005), File No. 1-9210).
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).
3.(i)(b)	Certificate of Amendment of Restated Certificate of Incorporation of Occidental Petroleum Corporation, dated May 5, 2006.
3.(ii)*	Bylaws of Occidental, as amended through July 20, 2006 (filed as Exhibit 3.(ii) to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended June 30, 2006, File No. 1-9210).
4.1*	Occidental Petroleum Corporation Amended and Restated Five-Year Credit Agreement, dated as of September 27, 2006, among Occidental; J.P. Morgan Securities Inc. and Citigroup Global Markets Inc., as Co-Arrangers and Joint Bookrunners; JPMorgan Chase Bank, N.A. and Citibank, N.A., as Co-Syndication Agents, BNP Paribas, Bank of America, N.A., Barclays Bank PLC and The Royal Bank of Scotland plc, as Co-Documentation Agents, The Bank of Nova Scotia, as Administrative Agent (filed as Exhibit 4.1 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended September 30, 2006, 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 10.70 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*	Amended and Restated Employment Agreement, dated as of February 10, 2005, between Occidental and Dr. Ray R. Irani (filed as Exhibit 10.1 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2004, File No. 1-9210).
10.2*	Employment Agreement, dated as of January 13, 2005, between Occidental and Stephen I. Chazen (filed as Exhibit 10.5 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2004, File No. 1-9210).
10.3*	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).
10.4*	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).
10.5*	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).
10.6*	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).

_________________________

* Incorporated herein by reference

10.7*	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).
10.8*	Occidental Petroleum Corporation Modified Deferred Compensation Plan (filed as Exhibit 10.12 to the Current Report on Form 8-K of Occidental dated October 12, 2006 (date of earliest event reported), File No. 1-9210).
10.9	Amendment No. 1 to Occidental Petroleum Corporation Modified Deferred Compensation Plan, effective as of January 1, 2007.
10.10*	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).
10.11*	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).
10.12*	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).
10.13*	Occidental Petroleum Corporation 1996 Restricted Stock Plan for Non-Employee Directors, amended as of February 10, 2005 (filed as Exhibit 10.2 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended March 31, 2005, File No. 1-9210).
10.14*	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).
10.15*	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).
10.16*	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).
10.17*	Amendment Number 2 to the Occidental Petroleum Corporation Supplemental Retirement Plan (As Amended and Restated Effective January 1, 1999 Reflecting Amendments Effective through March 1, 2001) (filed as Exhibit 10.1 to the Current Report on Form 8-K of Occidental dated December 7, 2004 (date of earliest event reported), filed December 8, 2004, File No. 1-9210.
10.18*	Summary of Material Terms and Conditions of Supplemental Retirement Allocations (effective as of January 1, 2005) (filed as Exhibit 10.39 to the Current Report on Form 8-K of Occidental dated April 6, 2005 (date of earliest event reported), filed April 6, 2005, File No. 1-9210).
10.19*	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).
10.20*	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).
10.21*	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).
10.22*	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).
10.23*	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).

_________________________

* Incorporated herein by reference

10.24*	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).
10.25*	Global Restricted Stock Unit Amendment to the 2002 Terms and Conditions (filed as Exhibit 10.2 to the Current Report on Form 8-K of Occidental dated October 12, 2006 (date of earliest event reported), File No. 1-9210).
10.26*	Amended And Restated Performance-Based Stock Award Terms And Conditions For January 1, 2003 Grant (Effective June 20, 2005) (Corporate) (filed as Exhibit 10.4 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended June 30, 2005, File No. 1-9210).
10.27*	Amended And Restated Performance-Based Stock Award Terms And Conditions For January 1, 2003 Grant (Effective June 20, 2005) (Chemicals) (filed as Exhibit 10.5 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended June 30, 2005, File No. 1-9210).
10.28*	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).
10.29*	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).
10.30*	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).
10.31*	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) (filed as Exhibit 10.45 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2003, File No. 1-9210).
10.32*	Global Restricted Stock Unit Amendment to the 2003 Terms and Conditions (filed as Exhibit 10.3 to the Current Report on Form 8-K of Occidental dated October 12, 2006 (date of earliest event reported), File No. 1-9210).
10.33*	Amended And Restated Performance-Based Stock Award Terms And Conditions For January 1, 2004 Grant (Effective June 20, 2005) (Corporate) (filed as Exhibit 10.6 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended June 30, 2005, File No. 1-9210).
10.34*	Amended And Restated Performance-Based Stock Award Terms And Conditions For January 1, 2004 Grant (Effective June 20, 2005) (Chemicals) (filed as Exhibit 10.7 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended June 30, 2005, File No. 1-9210).
10.35*	Amended And Restated Performance-Based Stock Award Terms And Conditions For January 1, 2004 Grant (Effective June 20, 2005) (Oil and Gas) (filed as Exhibit 10.8 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended June 30, 2005, File No. 1-9210).
10.36*	Terms and Conditions of Stock Appreciation Rights Award under Occidental Petroleum Corporation 2001 Incentive Compensation Plan (filed as Exhibit 10.3 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended June 30, 2004, File No. 1-9210).
10.37*	Terms and Conditions of Restricted Share Unit Award (without deferred issuance of shares) under Occidental Petroleum Corporation 2001 Incentive Compensation Plan (filed as Exhibit 10.4 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended June 30, 2004, File No. 1-9210).
10.38*	Global Restricted Stock Unit Amendment to the July 2004 Terms and Conditions (filed as Exhibit 10.6 to the Current Report on Form 8-K of Occidental dated October 12, 2006 (date of earliest event reported), File No. 1-9210).
10.39*	Terms and Conditions of Restricted Share Unit Award under Occidental Petroleum Corporation 2001 Incentive Compensation Plan (December 2004 version) (filed as Exhibit 10.57 to the Annual Report on Form 10-K for the fiscal year ended December 31, 2004, File No. 1-9210).
10.40*	Global Restricted Stock Unit Amendment to the 2004 Terms and Conditions (filed as Exhibit 10.4 to the Current Report on Form 8-K of Occidental dated October 12, 2006 (date of earliest event reported), File No. 1-9210).

_________________________

* Incorporated herein by reference

10.41*	Amended And Restated Performance-Based Stock Award Terms And Conditions For January 1, 2005 Grant (Effective June 20, 2005) (Corporate) (filed as Exhibit 10.9 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended June 30, 2005, File No. 1-9210).
10.42*	Amended And Restated Performance-Based Stock Award Terms And Conditions For January 1, 2005 Grant (Effective June 20, 2005) (Chemicals) (filed as Exhibit 10.10 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended June 30, 2005, File No. 1-9210).
10.43*	Amended And Restated Performance-Based Stock Award Terms And Conditions For January 1, 2005 Grant (Effective June 20, 2005) (Oil and Gas) (filed as Exhibit 10.11 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended June 30, 2005, File No. 1-9210).
10.44*	Occidental Petroleum Corporation 2005 Long-Term Incentive Plan (filed as Exhibit 99.1 to Occidental's Registration Statement on Form S-8, File No. 333-124732).
10.45*	Terms and Conditions of Stock Appreciation Rights Award under Occidental Petroleum Corporation 2005 Long-Term Incentive Plan (filed as Exhibit 10.12 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended June 30, 2005, File No. 1-9210).
10.46*	Terms and Conditions of Restricted Share Unit Award under Occidental Petroleum Corporation 2005 Long-Term Incentive Plan (filed as Exhibit 10.13 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended June 30, 2005, File No. 1-9210).
10.47*	Terms and Conditions of Restricted Share Unit Award (mandatory deferred issuance of shares) under Occidental Petroleum Corporation 2005 Long-Term Incentive Plan (filed as Exhibit 10.14 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended June 30, 2005, File No. 1-9210).
10.48*	Global Restricted Stock Unit Amendment to the July 2005 Terms and Conditions (filed as Exhibit 10.7 to the Current Report on Form 8-K of Occidental dated October 12, 2006 (date of earliest event reported), File No. 1-9210).
10.49*	Agreement to Amend Outstanding Option Awards, dated October 26, 2005 (filed as Exhibit 10.2 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended September 30, 2005, File No. 1-9210).
10.50*	Terms and Conditions of Restricted Share Unit Award (mandatory deferred issuance of shares) under Occidental Petroleum Corporation 2005 Long-Term Incentive Plan (December 2005 version) (filed as Exhibit 10.62 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2005, File No. 1-9210).
10.51*	Global Restricted Stock Unit Amendment to the 2005 Terms and Conditions (filed as Exhibit 10.5 to the Current Report on Form 8-K of Occidental dated October 12, 2006 (date of earliest event reported), File No. 1-9210).
10.52*	Terms and Conditions of Performance-Based Stock Award (deferred issuance of shares) under Occidental Petroleum Corporation 2005 Long-Term Incentive Plan (January 2006 version – Corporate) (filed as Exhibit 10.63 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2005, File No. 1-9210).
10.53*	Terms and Conditions of Performance-Based Stock Award (deferred issuance of shares) under Occidental Petroleum Corporation 2005 Long-Term Incentive Plan (January 2006 version – Oil and Gas) (filed as Exhibit 10.64 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2005, File No. 1-9210).
10.54*	Terms and Conditions of Performance-Based Stock Award (deferred issuance of shares) under Occidental Petroleum Corporation 2005 Long-Term Incentive Plan (January 2006 version – Chemicals) (filed as Exhibit 10.65 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2005, File No. 1-9210).
10.55*	Terms and Conditions of Target Performance-Based Restricted Share Unit Award Under Occidental Petroleum Corporation 2005 Long-Term Incentive Plan (filed as Exhibit 10.1 to the Current Report on Form 8-K of Occidental dated July 19, 2006 (date of earliest event reported), File No. 1-9210).
10.56*	Terms and Conditions of Stock Appreciation Rights (SARs) under Occidental Petroleum Corporation 2005 Long-Term Incentive Plan (July 2006 version) (filed as Exhibit 10.4 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended June 30, 2006, File No. 1-9210).
10.57*	Terms and Conditions of Restricted Share Unit Award under Occidental Petroleum Corporation 2005 Long-Term Incentive Plan (July 2006 version) (filed as Exhibit 10.5 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended June 30, 2006, File No. 1-9210).

_________________________

* Incorporated herein by reference

10.58*	Global Performance-Based Stock Amendment (filed as Exhibit 10.8 to the Current Report on Form 8-K of Occidental dated October 12, 2006 (date of earliest event reported), File No. 1-9210).
10.59*	Occidental Petroleum Corporation 2005 Deferred Stock Program (Restatement Effective as of January 1, 2005) (filed as Exhibit 10.68 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2005, File No. 1-9210).
10.60*	Amendment to Occidental Petroleum Corporation 2005 Deferred Stock Program (filed as Exhibit 10.2 to the Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2006, File No. 1-9210).
10.61*	Amendment No. 2 to the Occidental Petroleum Corporation 2005 Deferred Stock Program (filed as Exhibit 10.1 to the Current Report on Form 8-K of Occidental dated October 12, 2006 (date of earliest event reported), File No. 1-9210).
10.62*	Occidental Petroleum Corporation Executive Incentive Compensation Plan (filed as Exhibit 10.69 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2005, File No. 1-9210).
10.63*	Description of financial counseling program (filed as Exhibit 10.50 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2003, File No. 1-9210).
10.64*	Description of group excess liability insurance program (filed as Exhibit 10.51 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2003, File No. 1-9210).
10.65*	Executive Stock Ownership Guidelines (filed as Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2005, File No. 1-9210)
10.66*	Form of Restricted Stock Award for Non-Employee Directors under Occidental Petroleum Corporation 2005 Long-Term Incentive Plan (filed as Exhibit 10.1 to the Current Report on Form 8-K of Occidental dated February 16, 2006 (date of earliest event reported), filed February 22, 2006, File No. 1-9210)
10.67*	Director Retainer and Attendance Fees (filed as Exhibit 10.2 to the Current Report on Form 8-K of Occidental dated February 16, 2006 (date of earliest event reported), filed February 22, 2006, File No. 1-9210)
10.68	Terms and Conditions of Performance-Based Stock Award under Occidental Petroleum Corporation 2005 Long-Term Incentive Plan (January 2007 version – Corporate)
10.69	Terms and Conditions of Performance-Based Stock Award under Occidental Petroleum Corporation 2005 Long-Term Incentive Plan (January 2007 version – Oil and Gas)
10.70	Terms and Conditions of Performance-Based Stock Award under Occidental Petroleum Corporation 2005 Long-Term Incentive Plan (January 2007 version – Chemicals)
10.71*	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).
10.72*	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).
10.73*	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).
10.74*	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 each of the five years in the period ended December 31, 2006.
21	List of subsidiaries of Occidental at December 31, 2006.
23.1	Independent Registered Public Accounting Firm's Consent.
23.2	Expert 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

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
February 27, 2007	By:	/s/ RAY R. IRANI
		Ray R. Irani Chairman of the Board of Directors, President 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 Directors,	February 27, 2007
Ray R. Irani	President and Chief Executive Officer
/s/ STEPHEN I. CHAZEN	Senior Executive Vice President	February 27, 2007
Stephen I. Chazen	and Chief Financial Officer
/s/ JIM A. LEONARD	Vice President and Controller	February 27, 2007
Jim A. Leonard	(Principal Accounting Officer)
/s/ SPENCER ABRAHAM	Director	February 27, 2007
Spencer Abraham
/s/ RONALD W. BURKLE	Director	February 27, 2007
Ronald W. Burkle
/s/ JOHN S. CHALSTY	Director	February 27, 2007
John S. Chalsty
/s/ EDWARD P. DJEREJIAN	Director	February 27, 2007
Edward P. Djerejian
/s/ R. CHAD DREIER	Director	February 27, 2007
R. Chad Dreier
/s/ JOHN E. FEICK	Director	February 27, 2007
John E. Feick

Signature	Title	Date
/s/ IRVIN W. MALONEY	Director	February 27, 2007
Irvin W. Maloney
/s/ RODOLFO SEGOVIA	Director	February 27, 2007
Rodolfo Segovia
/s/ AZIZ D. SYRIANI	Director	February 27, 2007
Aziz D. Syriani
/s/ ROSEMARY TOMICH	Director	February 27, 2007
Rosemary Tomich
/s/ WALTER L. WEISMAN	Director	February 27, 2007
Walter L. Weisman

EXHIBITS

3.(i)(b)	Certificate of Amendment of Restated Certificate of Incorporation of Occidental Petroleum Corporation, dated May 5, 2006.
10.9	Amendment No. 1 to Occidental Petroleum Corporation Modified Deferred Compensation Plan, effective as of January 1, 2007.
10.68	Terms and Conditions of Performance-Based Stock Award under Occidental Petroleum Corporation 2005 Long-Term Incentive Plan (January 2007 version – Corporate)
10.69	Terms and Conditions of Performance-Based Stock Award under Occidental Petroleum Corporation 2005 Long-Term Incentive Plan (January 2007 version – Oil and Gas).
10.70	Terms and Conditions of Performance-Based Stock Award under Occidental Petroleum Corporation 2005 Long-Term Incentive Plan (January 2007 version – Chemicals).
12	Statement regarding computation of total enterprise ratios of earnings to fixed charges for each of the five years in the period ended December 31, 2006.
21	List of subsidiaries of Occidental at December 31, 2006.
23.1	Independent Registered Public Accounting Firm's Consent.
23.2	Expert 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.