SEC Filing | Occidental Petroleum Corporation

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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, 2007

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).

Large Accelerated Filer þ

Accelerated Filer o Non-Accelerated Filer o

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 $47.1 billion, computed by reference to the closing price on the New York Stock Exchange composite tape of $57.88 per share of Common Stock on June 30, 2007. 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, 2008, there were 822,567,021 shares of Common Stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s definitive Proxy Statement, filed in connection with its May 2, 2008, 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	4
	Available Information	4
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	16
	Segment Results of Operations	16
	Significant Items Affecting Earnings	18
	Taxes	19
	Consolidated Results of Operations	19
	Consolidated Analysis of Financial Position	20
	Liquidity and Capital Resources	21
	Off-Balance-Sheet Arrangements	22
	Lawsuits, Claims, Commitments, Contingencies and Related Matters	23
	Environmental Liabilities and Expenditures	24
	Foreign Investments	26
	Critical Accounting Policies and Estimates	26
	Significant Accounting Changes	28
	Derivative Activities and Market Risk	29
	Safe Harbor Discussion Regarding Outlook and Other Forward-Looking Data	31
Item 8	Financial Statements and Supplementary Data	32
	Management's Annual Assessment of and Report on Internal Control Over Financial Reporting	32
	Report of Independent Registered Public Accounting Firm on Consolidated Financial Statements	33
	Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting	34
	Consolidated Statements of Income	35
	Consolidated Balance Sheets	36
	Consolidated Statements of Stockholders’ Equity	38
	Consolidated Statements of Comprehensive Income	38
	Consolidated Statements of Cash Flows	39
	Notes to Consolidated Financial Statements	40
	Quarterly Financial Data (Unaudited)	73
	Supplemental Oil and Gas Information (Unaudited)	75
	Financial Statement Schedule:
	Schedule II – Valuation and Qualifying Accounts	83
Item 9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	84
Item 9A	Controls and Procedures	84
	Disclosure Controls and Procedures	84

Part III

Item 10	Directors, Executive Officers and Corporate Governance	84
Item 11	Executive Compensation	84
Item 12	Security Ownership of Certain Beneficial Owners and Management	84
Item 13	Certain Relationships and Related Transactions and Director Independence	84
Item 14	Principal Accountant Fees and Services	84

Part IV

Item 15

Exhibits and Financial Statement Schedules

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 and affiliates. The subsidiaries and other affiliates in the oil and gas segment explore for, develop, produce and market crude oil, natural gas liquids (NGL) 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 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, Utah and western Colorado. International operations are located in Argentina, Bolivia, Colombia, Libya, Oman, Qatar, the United Arab Emirates (UAE) and Yemen. 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 2007, 2006 and 2005. See the MD&A section of this report, Note 16 to the Consolidated Financial Statements and the information under the caption “Supplemental Oil and Gas Information” in Item 8 of this report for certain details regarding Occidental’s oil and gas proved reserves, the estimation process and production by country. On May 1, 2007, Occidental reported to the United States Department of Energy on Form EIA-28 proved oil and gas reserves at December 31, 2006. The amounts reported were the same as those reported in Occidental’s 2006 Annual Report.

Comparative Oil and Gas Proved Reserves and Production

Oil and NGLs in millions of barrels; natural gas in billions of cubic feet; BOE in millions of barrels of oil equivalent

	2007					2006					2005
RESERVES	Oil	^(a)	Gas	BOE	^(b)	Oil	^(a)	Gas	BOE	^(b)	Oil	^(a)	Gas	BOE	^(b)
United States	1,707		2,672	2,152		1,660		2,424	2,064		1,616		2,323	2,003
International	519		1,171	714		553		1,300	769		346		1,051	521
Consolidated Subsidiaries ^(c)	2,226		3,843	2,866	^(d)	2,213		3,724	2,833	^(d)	1,962		3,374	2,524	^(d)
Other Interests ^(e)	(2	)	—	(2	)	30		—	30		45		—	45
PRODUCTION
United States	95		216	131		94		214	130		87		199	120
International	70		45	78		66		23	70		48		16	51
Consolidated Subsidiaries ^(c)	165		261	209		160		237	200		135		215	171
Other Interests ^(e)	(1	)	—	(1	)	7		8	8		7		6	8

(a)	Includes natural gas liquids and condensate.
(b)	Natural gas volumes have been converted to barrels of oil equivalent (BOE) based on energy content of six Mcf of gas to one barrel of oil.
(c)	Occidental has classified its Pakistan, Horn Mountain and Ecuador 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 449 million BOE (MMBOE) and 104 MMBOE in 2007, 486 MMBOE and 119 MMBOE in 2006 and 472 MMBOE and 104 MMBOE in 2005, respectively.
(e)	The 2007 amounts reflect the minority interest in a Colombia subsidiary, partially offset by Occidental's share of reserves and production from an equity investee in Yemen. The 2006 and 2005 amounts include Occidental's share of reserves and production from an equity investee in Yemen and a Russian joint venture, partially offset by the minority interest in a Colombian subsidiary. Occidental's joint venture interest in Russia was sold in 2007.

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 its 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 domestic sites in Alabama, Georgia, Illinois, Kansas, Kentucky, Louisiana, New Jersey, New York, Ohio, Pennsylvania and Texas and at 3 international sites in Brazil, Canada and Chile. OxyChem produces the following chemical products:

Principal Products	Major Uses	Annual Capacity ^(a)
*Basic Chemicals*
Chlorine	Chlorovinyl chain and water treatment	4.0 million tons^(b)
Caustic Soda	Pulp, paper and aluminum production	4.3 million tons^(b)
Chlorinated organics	Silicones, paint stripping, pharmaceuticals and refrigerants	0.9 billion pounds
Potassium chemicals	Glass, fertilizers, cleaning products and rubber	0.3 million tons
Ethylene dichloride (EDC)	Raw material for vinyl chloride monomer (VCM)	2.4 billion pounds ^(b)
*Vinyls*
VCM	Precursor for polyvinyl chloride (PVC)	6.2 billion pounds
PVC	Piping, medical, building materials and automotive products	4.3 billion pounds
*Performance Chemicals*
Chlorinated isocyanurates	Swimming pool sanitation and disinfecting products	131 million pounds
Resorcinol	Tire manufacture, wood adhesives and flame retardant synergist	50 million pounds
Sodium silicates	Soaps, detergents and paint pigments	0.7 million tons

(a)	Estimated at December 31, 2007.
(b)	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 approximately 9,700 people at December 31, 2007, 6,600 of whom were located in the United States. Occidental employed approximately 5,200 people in oil and gas operations and 3,100 people in chemical operations. An additional 1,400 people were employed in administrative and headquarters functions. Approximately 800 United States-based employees and 150 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, competing fuel prices, prevailing currency exchange rates, price speculation, changes in consumption patterns, weather and geophysical and technical limitations and other matters discussed in this item 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 United States and global economy, as well as chemical industry expansion cycles. Occidental also depends on feedstocks and energy to produce chemicals, which are commodities subject to significant price fluctuations.

Occidental’s oil and gas business operates in highly competitive environments, which affect, 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. Occidental replaces significant amounts of its reserves through acquisitions and large development projects. 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 investment opportunities;
Ø	purchase properties or take on projects of lesser quality; 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 and supplies needed for production.

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

Occidental’s businesses are 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, climate change and energy security, all of which may increase costs or reduce the demand for Occidental's products;
Ø	expropriation or reduction of entitlements to produce hydrocarbons; and
Ø	refusal to extend or grant, or delay in the extension or grant of, 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, and events such as well blowouts, oilfield fires, industrial accidents and other events that cause operations to cease 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 could 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; miscalculate reserves or production or experience 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

Two OPC subsidiaries have entered into a settlement with the Office of the District Attorney (ODA) for Ventura County, California, acting on behalf of the California Department of Fish and Game (Department), to resolve alleged statutory violations arising from past releases of petroleum and production waters from operations in Ventura County acquired in early 2006. The settlement requires the subsidiaries to pay $150,000 in civil penalties, $98,640 for alleged damages to natural resources and $109,248 to reimburse costs incurred by the Department, and to install a leak detection system on certain oil and produced water transfer pipelines for an amount no less than $150,000. The settlement is expected to be entered as a Final Judgment and Permanent Injunction by a Ventura County Superior Court in the first quarter of 2008.

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

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 2007.

EXECUTIVE OFFICERS

The current term of employment of each executive officer of Occidental will expire at the May 2, 2008 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 22, 2008	Positions with Occidental and Subsidiaries and Five-Year Employment History
Dr. Ray R. Irani	73	Chairman and Chief Executive Officer since 1990; Director since 1984; Member of Executive Committee and Dividend Committee; 2005-2007, President.
Stephen I. Chazen	61	President since 2007; Chief Financial Officer since 1999; 2005-2007, Senior Executive Vice President; 1994-2004, Executive Vice President — Corporate Development.
Donald P. de Brier	67	Executive Vice President, General Counsel and Secretary since 1993.
Richard W. Hallock	63	Executive Vice President — Human Resources since 1994.
James M. Lienert	55	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	54	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	54	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	66	Vice President and Treasurer since 1998.
Jim A. Leonard	58	Vice President and Controller since 2005; 2000-2005, Senior Assistant Controller; OOGC: 2000-2005, Senior Vice President — Finance.
B. Chuck Anderson	48	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 40,214 stockholders of record at December 31, 2007, and by at least 345,000 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 stockholders 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 2007, the quarterly dividends declared for the common stock were $0.22 per share for the first two quarters of 2007 and $0.25 for the last two quarters of 2007 ($0.94 for the year). On February 14, 2008, a quarterly dividend of $0.25 per share ($1.00 on an annualized basis) was declared on the common stock, payable on April 15, 2008 to stockholders of record on March 10, 2008. 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 or other equity awards 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, 2007, pursuant to outstanding options, rights or warrants or other equity awards 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))

9,940,164

$35.83

59,464,546 *

* Includes, with respect to:
•	the 1995 Incentive Stock Plan, 5,602 shares reserved for issuance pursuant to deferred stock units awards;
•	the 2001 Incentive Compensation Plan, 1,235,966 shares at maximum payout level (617,983 at target level) reserved for issuance pursuant to outstanding performance stock awards, 178,000 shares reserved for issuance pursuant to restricted stock unit awards, 577,916 shares reserved for issuance pursuant to deferred stock unit awards and 767 shares reserved for issuance as dividend equivalents on deferred stock unit awards; and
•	the 2005 Long-Term Incentive Plan, 709,734 shares at maximum payout level (354,867 at target level) reserved for issuance pursuant to outstanding performance stock awards, 1,341,797 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, 784,308 shares at maximum payout level (522,872 at target level) reserved for issuance pursuant to total shareholder return incentive awards and 367,732 shares reserved for issuance pursuant to deferred stock unit awards.
Of the 52,746,724 shares that are not reserved for issuance under the 2005 Long-Term Incentive Plan, approximately 43.3 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 43.3 million shares may be issued or reserved for issuance for options, rights and warrants as well as performance stock awards, restricted stock unit awards, performance restricted stock unit awards, total shareholder return incentive awards, stock bonuses and dividend equivalents.

SHARE REPURCHASE ACTIVITIES

Occidental’s share repurchase activities for the year ended December 31, 2007, 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

Maximum Number of

Shares that May Yet be

Purchased Under the

Plans or Programs

First Quarter 2007

6,991,271

$45.89

6,989,956

Second Quarter 2007

4,188,481

$56.42

3,716,500

Third Quarter 2007

6,236,667

$56.63

5,876,500

October 1 - 31, 2007

758,183

^(a,b)

$66.22

437,500

November 1 - 30, 2007

2,012,800

$68.43

2,012,800

December 1 - 31, 2007

443,175

^(a)

$70.69

300,000

Fourth Quarter 2007

3,214,158

$68.22

2,750,300

Total 2007

20,630,577

$54.75

19,333,256

6,342,944

^(c,d)

(a)	Occidental purchased from the trustee of Occidental's defined contribution savings plan 320,492 shares in October and 143,175 shares in December.
(b)	Amount includes employee stock-for-stock exercises of 191 shares in October 2007.
(c)	Occidental has authorized a buy back of 55 million shares for its share repurchase program.
(d)	In February 2008, Occidental increased the number of shares authorized for its previously announced share repurchase program from 55 to 75 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, 2007. 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.

In 2007, Occidental revised its peer group by including two international-based oil and gas companies to reflect the peer companies that Occidental competes against for major global projects and removing Hess Corporation, which is primarily a domestic company with significant refining operations. The revised peer group consists of Anadarko Petroleum Corporation, Apache Corporation, BP p.l.c. (BP), Chevron Corporation, ConocoPhillips, Devon Energy Corporation, ExxonMobil Corporation, Royal Dutch Shell plc and Occidental. Analysis for the revised peer group includes five years of historical performance data as noted above for the common stock of each of the companies. The prior peer group used in the analysis last year consisted of Anadarko Petroleum Corporation, Apache Corporation, Chevron Corporation, ConocoPhillips, Devon Energy Corporation, ExxonMobil Corporation, Hess Corporation and Occidental.

12/31/02		12/31/03	12/31/04	12/31/05	12/31/06	12/31/07
	$100	$153	$216	$301	$374	$599
	100	126	163	194	255	333
	100	125	156	182	226	283
	100	129	143	150	173	183
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,	2007			2006			2005			2004			2003
RESULTS OF OPERATIONS ^(a)
Net sales	$	18,784		$	17,175		$	14,153		$	10,400		$	8,598
Income from continuing operations	$	5,078		$	4,202		$	4,838		$	2,197		$	1,410
Net income	$	5,400		$	4,191		$	5,293		$	2,574		$	1,537
Basic earnings per common share from continuing operations	$	6.08		$	4.93		$	6.00		$	2.78		$	1.84
Basic earnings per common share	$	6.47		$	4.92		$	6.56		$	3.25		$	2.00
Diluted earnings per common share	$	6.44		$	4.87		$	6.47		$	3.21		$	1.98
FINANCIAL POSITION ^(a)
Total assets	$	36,519		$	32,431		$	26,170		$	21,440		$	18,210
Long-term debt, net and trust preferred securities ^(b)	$	1,741		$	2,619		$	2,873		$	3,345		$	4,446
Stockholders’ equity	$	22,823		$	19,252		$	15,091		$	10,597		$	7,970
MARKET CAPITALIZATION ^(c)	$	63,573		$	41,013		$	32,121		$	23,153		$	16,349
CASH FLOW
Cash provided by operating activities	$	6,798		$	6,353		$	5,337		$	3,878		$	3,074
Capital expenditures	$	(3,497	)	$	(2,987	)	$	(2,295	)	$	(1,703	)	$	(1,481	)
Cash provided (used) by all other investing activities, net	$	369		$	(1,396	)	$	(866	)	$	(725	)	$	(650	)
DIVIDENDS PER COMMON SHARE	$	0.94		$	0.80		$	0.645		$	0.55		$	0.52
BASIC SHARES OUTSTANDING (thousands)		834,932			852,550			806,600			791,159			767,887

(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)	On January 20, 2004, Occidental redeemed the trust preferred securities.
(c)	Market capitalization is calculated by multiplying the year-end total shares of common stock outstanding, net of shares held in treasury stock, by the year-end closing stock price.

ITEM 7

Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) (Incorporating Item 7A)

STRATEGY

General

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’s business is divided into two segments conducted through oil and gas subsidiaries and their affiliates and chemical subsidiaries and their affiliates. 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 to enhance stockholders' returns by continuing its program for evaluating dividend increases and potential stock repurchases.

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 improve the competitiveness of these assets. Asset acquisitions may be pursued when they are expected to enhance the existing core chlor-alkali and polyvinyl chloride (PVC) businesses. Historically, the chemical segment has generated cash flow exceeding its normal capital expenditure requirements.

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 United Arab Emirates (UAE), the Mukhaizna project in Oman, and Libya for continued growth opportunities.

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 in 1998, followed by a series of purchases in the Permian Basin in west Texas and New Mexico and the integration of Vintage Petroleum, Inc. (Vintage) and Plains Exploration and Production Company (Plains) operations acquired in 2006.

At the end of 2007, the Elk Hills and Permian assets made up 66 percent of Occidental’s consolidated proven oil reserves and 44 percent of its consolidated proven gas reserves. On a barrels of oil equivalent (BOE) basis, these assets accounted for 61 percent of Occidental’s consolidated reserves. In 2007, the combined production from these assets averaged approximately 286,000 barrels of oil equivalent (BOE) per day.

Chemical

Segment Income

($ millions)

OxyChem’s strategy is to be a low-cost producer in order to maximize its cash flow generation. OxyChem concentrates on the chlorovinyls chain beginning with chlorine, which is coproduced with caustic soda, after which chlorine and ethylene are converted through a series of intermediate products into 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, reserves replacement percentage and other similar measures.

Debt Structure

Occidental’s year-end 2007 total debt-to-capitalization ratio declined to 7 percent from 36 percent at the end of 2003. During that time, Occidental has reduced its debt over 60 percent while increasing its stockholders' equity by 186 percent.

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 (Moody's), and A(Low) by Dominion Bond Rating Service. In July 2007, Fitch Ratings upgraded Occidental's long-term senior unsecured debt rating from A- to A. In December 2007, Moody's and Standard and Poor's raised their outlook on Occidental's credit ratings from stable to positive. 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 2007 ^(a)		Three-Year Average 2005 - 2007 ^(b)
26%		29%

(a)	The Return on Equity for 2007 was calculated by dividing Occidental's 2007 net income by the average equity balance in 2007.
(b)	The three-year average Return on Equity was calculated by dividing the average net income over the three-year period 2005-2007 by the average equity balance over the same period.

Occidental has focused on achieving top quartile return on equity. In 2007, Occidental's return on equity was 26 percent and the three-year average return on equity was 29 percent. During the same three-year period, Occidental increased its stockholders’ equity by 115 percent and its annual dividend by 82 percent while its stock price increased by 164 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 2007 over 2006 levels and ended the year higher than 2006 year-end levels. During 2007, Occidental experienced an improvement 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 90 percent and 87 percent for 2007 and 2006, 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 2007 was $72.32 per barrel compared with $66.23 per barrel in 2006. Occidental's average realized price for oil in 2007 was $64.77 per barrel, compared with $57.81 per barrel in 2006.

The average New York Mercantile Exchange (NYMEX) domestic natural gas prices decreased approximately 9 percent from 2006. For 2007, NYMEX gas prices averaged $7.12/Mcf compared with $7.82/Mcf for 2006.

Business Review

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

Worldwide Production

(thousands BOE/day)

Acquisitions and Dispositions

In June 2007, Occidental completed a fair value exchange in which BP p.l.c. (BP) acquired Occidental's oil and gas interests in Horn Mountain and received cash. Occidental acquired oil and gas interests in the Permian Basin and a gas processing plant in Texas from BP. Occidental also sold its oil and gas interests in Pakistan to BP. As a result of these transactions, both the Horn Mountain and Pakistan operations were classified as discontinued operations for all periods presented. The twelve months of 2007 include after-tax gains of $230 million related to these transactions.

In January 2007, Occidental sold its 50-percent joint venture interest in Russia for an after-tax gain of approximately $412 million.

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 19 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.

A significant portion of Occidental's Permian Basin interests were obtained through the acquisition of Altura Energy Ltd. in 2000. Additional acquisitions of oil and gas producing property interests were subsequently made. Occidental's total share of Permian Basin oil, gas and NGL production averaged approximately 198,000 BOE per day in 2007. At the end of 2007, 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. In 2007, Wasson San Andres was Occidental's largest Permian producing field with an average of approximately 38,000 BOE per day of production and with 311 million BOE of proved reserves at year-end. This field represents 19 percent of Occidental's 2007 daily Permian Basin production and 26 percent of its year-end Permian Basin proved reserves.

Occidental’s interests in the Permian Basin offer additional development and exploitation potential. During 2007, Occidental drilled approximately 225 wells on its operated properties and participated in additional wells drilled on outside-operated interests. Occidental conducted significant development activity on nine carbon dioxide (CO₂) projects during 2007, 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 127 well service units working in the Permian area during 2007 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.

California

Elk Hills

Occidental's interest at Elk Hills includes the Elk Hills oil and gas field in the southern portion of California’s San Joaquin Valley, which it operates with an approximately 78-percent interest, and other non-unit properties. The Elk Hills field is the largest producer of gas in California. Oil and gas production in 2007 from the Elk Hills properties was approximately 88,000 BOE per day. During 2007, Occidental continued to perform infill drilling, field extensions and recompletions identified by advanced reservoir characterization techniques, resulting in 246 new wells being drilled and 507 wells being worked over. At the end of 2007, the Elk Hills properties had an estimated 519 million BOE of proved reserves.

Vintage Production 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, located mainly in the Ventura, San Joaquin and Sacramento basins.

Oil and gas production from Vintage Production California in 2007 averaged approximately 22,000 BOE per day. At the end of 2007, the combined properties had an estimated 138 million BOE of proved reserves.

THUMS and Tidelands

Occidental owns THUMS, which conducts the field operations for an oil production unit offshore Long Beach, California. Occidental acquired Tidelands in 2006. Tidelands is the contract operator for an onshore oil production unit in Long Beach, California. Occidental's share of production and reserves from both properties is subject to contractual arrangements similar to a production sharing contract (PSC), whereby Occidental’s share of production and reserves vary inversely with oil prices. These contracts do not transfer any right of ownership to Occidental and reserves reported from these arrangements are based on Occidental’s economic interest as defined in the contracts.

For 2007, Occidental's production from THUMS averaged 20,000 BOE per day and proved reserves totaled 97 million BOE at year-end.

Hugoton and Other

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

Occidental also has over 29,000 net acres in the Piceance Basin in western Colorado. During 2007, Occidental drilled 56 wells in the basin.

In 2007, Occidental’s Hugoton and other operations produced approximately 30,000 BOE per day. At December 31, 2007, proved reserves totaled 154 million BOE from Hugoton and other operations.

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 NGLs in Qatar’s North Field for 25 years from the start of production, with a provision to request a 5-year extension. 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), and is recorded as an equity investment.

Dolphin Energy is the operator under the DPSA on behalf of the three DPSA participants, including Occidental. Dolphin Energy owns and operates a 230-mile-long, 48-inch natural gas pipeline, which transports dry natural gas from Qatar to the UAE. The transportation of gas through the pipeline started in the first quarter of 2007 using third-party natural gas and production under the DPSA began in July 2007 from Qatar’s North Field replacing the third-party natural gas. These contracts do not transfer any right of ownership to Occidental and reserves reported from these arrangements are based on Occidental’s economic interest as defined in the contracts. Occidental’s share of production was approximately 36,000 BOE per day in the fourth quarter of 2007 with production expected to increase to approximately 55,000 BOE per day in 2008. At December 31, 2007, Occidental’s share of proved oil and gas reserves from the Dolphin Project was 234 million BOE.

The Dolphin Project is expected to cost approximately $5.7 billion in total, including investments in the local UAE eastern gas distribution system, the Al Ain-Fujairah and Taweelah-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 $1.4 billion of this total, with $1.1 billion invested as of December 31, 2007.

At the end of 2007, all offshore facilities within the original scope of the project have been completed along with construction of three of the four trains in the onshore gas processing and compression plant at Ras Laffan. The fourth train is expected to be completed in the first quarter of 2008.

The pipeline has a capacity to transport up to 3.2 billion cubic feet (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.

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). In 2007, Occidental continued development of the ISND and ISSD fields to recover additional reserves through advanced drilling techniques and waterflood expansion. Capital expenditures in Qatar for the ISND and ISSD projects were $237 million in 2007.

In October 2007, Occidental acquired Anadarko Petroleum Corporation’s 92.5-percent interest in an exploration and production sharing agreement covering Blocks 12 and 13 located offshore Qatar. Block 13 is an exploration block.

These projects do not transfer any right of ownership to Occidental and reserves reported from these arrangements are based on Occidental’s economic interest as defined in the contracts. Occidental’s production from Block 12, ISND and ISSD averaged 48,000 BOE in 2007. Proved reserves reported for these properties totaled 128 million BOE at December 31, 2007.

Yemen

Occidental owns contractual interests in three producing blocks in Yemen, including a 38-percent direct-working interest in the Masila field, 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. In addition, Occidental owns an 80-percent working interest in Block 20 and is currently awaiting final approval from the Yemen government for a 75-percent working interest in Block 75.

These contracts do not transfer any right of ownership to Occidental and reserves reported from these arrangements are based on Occidental’s economic interest as defined in the contracts.

At December 31, 2007, production from the Yemen properties was 27,000 BOE per day and proved reserves totaled 24 million BOE.

Oman

In Oman, Occidental is the operator of Block 9 and Block 27, with a 65-percent working interest in each, Block 53, with a 45-percent working interest, and Block 54, with a 70-percent working interest. Occidental’s share of production from Blocks 9, 27 and 53 averaged 25,000 BOE per day in 2007.

The Block 9 agreement provides for two 10-year extensions and Occidental and its partner agreed with the Government of Oman to the first 10-year extension through December 7, 2015.

Occidental and its partners signed a 30-year PSC for the Mukhaizna field (Block 53) with the Government of Oman in 2005. In September 2005, Occidental assumed operations of the Mukhaizna field. The Mukhaizna field, located in Oman’s south central interior, was discovered in 1975 and was brought into production in 2000. By the end of 2007, Occidental had drilled over 175 new wells and continued implementation of a major pattern steam flood project. As of year-end 2007, the exit rate of gross daily production had nearly tripled from the production rate of September 2005. Occidental plans to steadily increase production through continued expansion of the steam flood project.

The exploitation term for Block 27 is 30 years beginning in September 2005. Occidental and its partners began production in June 2006.

Occidental and its partners signed a new PSC for Block 54 with the Government of Oman in June 2006 with an initial exploration phase of four years.

These contracts do not transfer any right of ownership to Occidental and reserves reported from these arrangements are based on Occidental’s economic interest as defined in the contracts.

Occidental’s proved reserves for all the Oman properties totaled 65 million BOE at December 31, 2007.

Libya

In 2005, Occidental signed an agreement with the Libya National Oil Corporation (NOC) which allowed it to re-enter the country and participate in exploration and production operations in the Sirte Basin, which it left in 1986 pursuant to United States law. This re-entry agreement allowed Occidental to return to its Libyan operations on generally the same terms in effect when activities were suspended. Occidental’s rights in the producing fields extend through 2009 and early 2010. These contracts do not transfer any right of ownership to Occidental and reserves reported from these arrangements are based on Occidental’s economic interest as defined in the contracts. Production during 2007 averaged 22,000 BOE per day. At year-end 2007, proved reserves reported for Occidental’s Libya assets totaled 16 million BOE.

In November 2007, Occidental announced that it had reached an agreement with NOC on new 30-year contracts for major field redevelopment and exploration in the Sirte Basin. The new contracts are subject to approval of the Libyan government. Total expected capital investment is estimated to be $5 billion over the next five years, of which Occidental's portion will be approximately $1.9 billion. Under the new

contracts, Occidental (which has a 75-percent working interest) and its partner would pay a signature bonus of $1 billion, of which Occidental's share is $750 million and which is payable over a three-year period. Occidental and its partner would also contribute 50 percent of the development capital to the project and receive approximately 10 to 12 percent of the gross production, depending on the specific field.

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 23 concessions located in the San Jorge Basin in southern Argentina and the Cuyo Basin and Neuquén Basin in western Argentina. Occidental operates 20 of the concessions with a 100-percent working interest.

During 2007, Occidental drilled 153 new wells and performed a number of recompletions and well repairs. Occidental expects to increase production significantly over the next four years through aggressive drilling, waterflooding and EOR projects. In 2008, Occidental plans to drill 220 wells, complete the eight waterflood projects initiated in 2007 and implement a number of new waterflood projects.

Occidental’s share of production from Argentina averaged 36,000 BOE per day in 2007. Proved reserves from these assets totaled 177 million BOE at December 31, 2007.

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. At the end of 2006, Occidental signed two new operation contracts with commercial terms that provide Bolivia with greater operational control and control over the commercialization of hydrocarbons. These contracts went into effect in May 2007.

Colombia

Occidental is the operator under four contracts within the Llanos Norte Basin: the Cravo Norte, Rondón, Cosecha, and Chipirón Association Contracts. Occidental’s working interests under the four contracts are 42 percent, 44 percent, 53 percent and 61 percent, respectively. Colombia's national oil company, Ecopetrol, operates the Caño Limón-Coveñas oil pipeline and marine-export terminal. The pipeline transports oil produced from the Llanos Norte Basin for export to international markets.

In the Middle-Magdalena Basin, Occidental signed an agreement with Ecopetrol in 2005 for an EOR project in the La Cira-Infantas (LCI) field, in which Occidental holds a 48-percent working interest. In December 2006, Occidental entered into the commercial phase of the project. Production from the field is transported by Ecopetrol through its pipeline and sold to Ecopetrol refineries.

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

Occidental's share of 2007 production from its Colombia operations was 37,000 BOE per day and proved reserves reported for these interests totaled 57 million BOE at the end of 2007.

Production-Sharing Contracts

Occidental conducts its operations in Qatar, Oman and Yemen under PSCs and, under such contracts, receives a share of production and reserves to recover its costs and an additional share for profit. In addition, Occidental's share of production and reserves from THUMS and Tidelands are subject to contractual arrangements similar to a PSC. These contracts do not transfer any right of ownership to Occidental and reserves reported from these arrangements are based on Occidental’s economic interest as defined in the contracts. 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.

Proved Reserves

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 2003.

Again in 2007, 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 2007, Ryder Scott reviewed approximately 10 percent of Occidental’s oil and gas reserves. Since being engaged in 2003, Ryder Scott has reviewed Occidental’s reserve estimation methods and procedures for approximately 57 percent of Occidental’s reported 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's consolidated subsidiaries had proved reserves at year-end 2007 of 2,866 million BOE, as compared with the year-end 2006 amount of 2,833 million BOE. The increase in the consolidated subsidiaries’ reserves from all sources was 242 million BOE, which was comprised of an increase of 297 million BOE from proved developed reserves, partially offset by a decrease of 55 million BOE from proved undeveloped reserves.

Proved developed reserves represented approximately 80 percent of Occidental’s total proved reserves at year-end 2007 compared to 78 percent at year-end 2006.

Proved Reserve Additions - Consolidated Subsidiaries - 2007

In Millions of BOE
Revisions of previous estimates	(95	)
Improved Recovery	253
Extensions and Discoveries	24
Purchases	60
Total Additions	242

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

Revisions of Previous Estimates

In 2007, Occidental experienced a reduction of 95 million BOE of proved reserves through negative revisions of previous estimates, primarily in the Dolphin Project, Qatar, Elk Hills, THUMS and Argentina, partially offset by positive revisions in Permian and Hugoton. Oil price changes 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 8 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 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 believes its 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 2007, Occidental added reserves of 253 million BOE through improved recovery. In the United States, improved recovery additions were 64 million BOE in the Elk Hills field, 52 million BOE in the Permian Basin and 29 million BOE in western Colorado. Foreign additions included 32 million BOE in Oman, 17 million BOE in Colombia and 15 million BOE in Qatar. 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 2007, as a result of such programs, Occidental added reserves of 24 million BOE, including 15 million BOE in Argentina, 3 million BOE in Oman and 2 million BOE in the Permian Basin.

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 2007, Occidental purchased reserves of 60 million BOE, of which 50 million BOE were in the United States and 10 million BOE were in the Middle East/North Africa. Occidental continues to add reserves through acquisitions when properties are available at prices it deems reasonable. 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 202 million BOE resulting from improved recovery, extensions and discoveries and purchases, primarily in the Elk Hills field, the Permian Basin, Oman and Argentina. Elk Hills provided 19 percent of this increase. These proved undeveloped reserve additions were offset by reserve transfers to the proved developed category as a result of 2007 development programs. The Dolphin Project transferred 101 million BOE to the proved developed category during 2007, with no remaining undeveloped reserves at year end. In the United States, the Elk Hills field and the Permian Basin each transferred 21 million BOE into proved developed reserves from proved undeveloped reserves.

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 rose throughout 2007 and reached historical highs during the last half of the year. 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 $38 per barrel over the past ten years. However, the industry has historically experienced wide fluctuations in 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 $5.03 per Mcf.

CHEMICAL SEGMENT

Business Environment

The chemical segment results decreased in 2007 due to the softening United States housing market and continued high feedstock costs, which led to lower margins in the PVC business. This was partially offset by an increase in demand for United States products in export markets in 2007 aided by expanding international economies along with favorable foreign currency exchange rates.

Business Review

Basic Chemicals

During 2007, demand and pricing for basic chemical products generally remained strong, although demand for domestic chlorine slightly weakened compared to 2006 due to a slowdown in the United States housing sector. Domestic industry demand for liquid caustic soda in 2007 was virtually flat compared to the prior year; however, industry export demand increased over 2006. Export demand was supported by increasing alumina capacity in South America as well as favorable currency exchange rates. Margins in 2007 continued at 2006 levels as pricing and feedstock costs remained relatively unchanged. Pricing for liquid caustic soda started the year strong and increased every quarter of 2007 aided by unplanned global supply disruptions and a strong export market. OxyChem’s chlor-alkali operating rate for 2007 was 92 percent, which was the same as the industry average operating rate for 2007.

Vinyls

Domestic demand for PVC in 2007 was 5 percent below 2006 as a result of the significant slump in housing. This was partially offset by exports from the United States, which were up 40 percent in 2007 over 2006, resulting in overall demand for PVC being down 2 percent in 2007. Compared to 2006, margins in 2007 decreased as price increases were not able to compensate for raw material cost increases. From early 2007 to the end of the year, industry PVC prices increased by 31 percent while the cost of ethylene increased by 56 percent. OxyChem operated its PVC facilities at an average operating rate of 78 percent for 2007, compared to the North American industry average of 85 percent.

Industry Outlook

In 2007, Occidental's chemical business earnings were lower than 2006, primarily due to the weakening of the United States housing market.

Future performance will depend on the recovery of United States construction activity, 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 United States economy offset by a continued strong export market in 2008 are expected to result in demand levels similar to 2007 levels. Despite continued pressure on the vinyls market, margins in 2008 are expected to remain similar to 2007, but could weaken in the second half due to the anticipated impact of capacity additions in mid 2008.

Vinyls

Industry-wide PVC operating rates are expected to be lower in 2008 as a result of weak demand, especially in housing, coupled with the start-up of new capacity in the first half of the year. Exports of United States produced products are expected to maintain their competitive advantage due to the weak United States dollar. Cost pressures are also expected to continue due to high feedstock costs.

CORPORATE AND OTHER

Corporate and Other includes investments in two cogeneration facilities in Taft, Louisiana and Ingleside, Texas and two common carrier pipelines in the Permian Basin, one of which was purchased in 2007, which are used in corporate-directed activities.

In 2007, Occidental resolved certain legal disputes that resulted in a gain of approximately $112 million.

On August 1, 2006, Occidental effected a two-for-one stock split in the form of a stock dividend to stockholders 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.

In October 2006, Occidental sold 10 million shares of Lyondell Chemical Company's (Lyondell) common stock in a registered public offering for a pre-tax gain of $90 million and gross proceeds of $250 million. In 2007, Occidental sold all of its remaining shares of Lyondell common stock (approximately 21 million shares) for a pre-tax gain of $326 million and gross proceeds of $672 million.

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,	2007			2006			2005
NET SALES
Oil and Gas	$	13,918		$	12,190		$	9,361
Chemical		4,664			4,815			4,641
Other ^(a)		202			170			151
	$	18,784		$	17,175		$	14,153
EARNINGS(LOSS)
Oil and Gas ^(b)	$	8,318		$	6,880		$	5,662
Chemical ^(c)		601			906			614
		8,919			7,786			6,276
Unallocated corporate items
Interest expense, net ^(d)		(199	)		(131	)		(201	)
Income taxes ^(e)		(3,507	)		(3,354	)		(1,841	)
Other ^(f)		(135	)		(99	)		604
Income from continuing
operations		5,078			4,202			4,838
Discontinued operations, net ^(g)		322			(11	)		452
Cumulative effect of changes in
accounting principles, net		—			—			3
Net Income	$	5,400		$	4,191		$	5,293
Basic Earnings per
Common Share	$	6.47		$	4.92		$	6.56

(a)	These amounts represent revenue from cogeneration plants and common carrier pipelines.
(b)	The 2007 amount includes an after-tax gain of $412 million from the sale of Occidental's interest in a Russian joint venture, an after-tax gain of $112 million from certain litigation settlements, a pre-tax gain of $103 million from the sale of exploration properties, a pre-tax gain of $35 million from the sale of miscellaneous domestic oil and gas interests and a $74 million pre-tax loss from the impairment of properties. The 2007, 2006 and 2005 amounts include interest income of $10 million, $10 million and $11 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 2007, 2006 and 2005 amounts include $167 million, $31 million and $42 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.
(f)	The 2007 amount includes a $326 million pre-tax gain from the sale of Occidental’s remaining investment in Lyondell, a $47 million pre-tax charge for a plant closure and related environmental remediation reserve and a $25 million pre-tax severance charge. The 2006 amount includes a $90 million pre-tax gain from the sale of 10 million shares of Lyondell and a $108 million pre-tax gain related to litigation settlements. The 2005 amount includes a $726 million pre-tax gain from Valero Energy Corporation's (Valero) acquisition of Premcor, Inc, (Premcor) and the subsequent sale of the Valero shares received and a $140 million pre-tax gain from the sale of 11 million shares of Lyondell common stock.
(g)	In June 2007, Occidental completed an exchange of oil and gas interests in Horn Mountain with BP for oil and gas interests in the Permian Basin and a gas processing plant in Texas. Occidental sold its oil and gas interests in Pakistan to BP. The 2007 amount includes after-tax income of $326 million related to these transactions and their operating results and a $4 million after-tax charge from assets classified to discontinued operations in 2006. In January 2006, Occidental completed the merger of Vintage into a subsidiary and classified certain assets and liabilities as held for sale. In May 2006, Ecuador terminated Occidental’s contract for the operation of Block 15. The 2006 amount includes a $253 million after-tax loss for Ecuador and the Vintage properties held for sale and $242 million after-tax income for the operations of Horn Mountain and Pakistan.

Oil and Gas

In millions, except as indicated

For the years ended December 31,	2007			2006			2005
Segment Sales	$	13,918		$	12,190		$	9,361
Segment Earnings	$	8,318		$	6,880		$	5,662
Net Production per Day
United States
Crude oil and liquids (MBBL)
California		89			86			76
Permian		167			167			161
Hugoton and other		4			3			3
Total		260			256			240
Natural Gas (MMCF)
California		254			256			242
Hugoton and other		153			138			133
Permian		186			194			170
Total		593			588			545
Latin America
Crude oil (MBBL)
Argentina		32			33			—
Colombia		42			38			36
Total		74			71			36
Natural Gas (MMCF)
Argentina		22			17			—
Bolivia		18			17			—
Total		40			34			—
Middle East/North Africa
Crude oil (MBBL)
Oman		20			18			17
Dolphin		4			—			—
Qatar		48			43			42
Yemen		25			29			28
Libya		22			23			8
Total		119			113			95
Natural Gas (MMCF)
Oman		30			30			44
Dolphin		51			—			—
Total		81			30			44
Barrels of Oil Equivalent (MBOE) ^(a)
Subtotal Consolidated
Subsidiaries		573			549			469
Colombia-minority interest		(5	)		(5	)		(4	)
Yemen-Occidental net interest		2			1			1
Total Worldwide Production
(MBOE) ^(b)		570			545			466

(See footnotes on next page)

Oil and Gas (continued)

In millions, except as indicated	2007		2006		2005
Average Sales Prices
Crude Oil Prices ($ per bbl)
United States	$	65.67	$	57.84	$	50.12
Latin America	$	56.66	$	52.40	$	51.18
Middle East/North Africa ^(c)	$	69.24	$	61.58	$	49.88
Total consolidated subsidiaries	$	64.86	$	57.81	$	50.19
Other interests	$	68.74	$	62.59	$	50.42
Total worldwide ^(b)	$	64.77	$	57.81	$	50.18
Gas Prices ($ per Mcf)
United States	$	6.53	$	6.49	$	7.10
Latin America	$	2.66	$	2.00	$	—
Total worldwide ^(b)	$	5.68	$	6.00	$	6.64
Expensed Exploration ^(d)	$	422	$	296	$	310
Capital Expenditures
Development	$	2,945	$	2,454	$	1,811
Exploration	$	159	$	155	$	246
Other	$	102	$	94	$	51

(a)	Natural gas volumes have been converted to BOE based on energy content of six Mcf of gas to one barrel of oil.
(b)	Occidental has classified its Pakistan, Horn Mountain and Ecuador operations as discontinued operations on a retrospective application basis and excluded them from this table. Excluded production from Pakistan operations averaged 17,000 BOE per day in 2006 and 18,000 BOE per day in 2005. Excluded production from Horn Mountain operations averaged 13,000 BOE per day in 2006 and 14,000 BOE per day in 2005. Excluded production from Ecuador operations averaged 43,000 BOE per day for the first five months of 2006 and 42,000 BOE per day in 2005. Also excluded is production from a Russian joint venture (sold in January 2007), which averaged 27,000 BOE per day and 28,000 BOE per day in 2006 and 2005, respectively.
(c)	These prices exclude the impact of taxes owed by Occidental but paid by governmental entities on its behalf.
(d)	Includes dry hole write-offs and lease impairments of $247 million in 2007, $115 million in 2006 and $216 million in 2005.

Oil and gas segment earnings in 2007 were $8.3 billion, compared to $6.9 billion in 2006. Oil and gas segment earnings in 2007 include an after-tax gain of $412 million from the sale of Occidental’s interest in a Russian joint venture, an after-tax gain of $112 million from certain litigation settlements, a pre-tax gain of $103 million from the sale of exploration properties, a pre-tax gain of $35 million from the sale of miscellaneous domestic oil and gas interests and a $74 million pre-tax loss from the impairment of properties. In addition to the matters discussed above, oil and gas segment earnings for 2007, compared to 2006, reflected higher crude oil prices and higher oil and gas production, partially offset by increased depreciation, depletion and amortization (DD&A) rates and higher operating and exploration expenses.

Oil and gas segment earnings in 2006 were $6.9 billion, compared to $5.7 billion in 2005. The increase in oil and gas segment earnings was primarily due to higher crude oil prices and oil and gas production, partially offset by higher operating expenses, including increased DD&A, which was driven by higher volumes and rates.

Average consolidated production costs for 2007 were $12.87 per BOE, compared to the average 2006 production cost of $11.70 per BOE. The increases resulted from higher field operating and maintenance costs.

Chemical

In millions	2007		2006		2005
Segment Sales	$	4,664	$	4,815	$	4,641
Segment Earnings	$	601	$	906	$	614
Capital Expenditures	$	251	$	251	$	173

Chemical segment earnings in 2007 were $601 million, compared to $906 million in 2006. The decrease in segment earnings is primarily due to lower margins in PVC.

Chemical segment earnings in 2006 were $906 million, compared to $614 million in 2005. The increase in chemical segment earnings is primarily due to higher margins in chlorine, caustic soda and PVC.

SIGNIFICANT ITEMS AFFECTING EARNINGS

The following table sets forth the effects of significant transactions and events affecting Occidental’s earnings that vary widely and unpredictably in nature, timing and amount for the years ended December 31, 2007, 2006 and 2005:

Significant Items Affecting Earnings

Benefit (Charge) (in millions)	2007			2006			2005
OIL AND GAS
Gain on sale of a Russian joint venture ^(a)	$	412		$	—		$	—
Legal settlements ^(a)		112			—			—
Gain on sale of exploration properties		103			—			—
Gain on sale of oil and gas interests		35			—			—
Impairments		(74	)		—			—
Contract settlement		—			—			(26	)
Hurricane insurance charge		—			—			(18	)
Total Oil and Gas	$	588		$	—		$	(44	)
CHEMICAL
Write-off of plants	$	—		$	—		$	(159	)
Hurricane insurance charge		—			—			(11	)
Total Chemical	$	—		$	—		$	(170	)
CORPORATE
Gain on sale of Lyondell shares	$	326		$	90		$	140
Debt purchase expense		(167	)		(31	)		(42	)
Facility closure		(47	)		—			—
Severance charge		(25	)		—			—
Deferred tax write-off due to
compensation program changes ^(a)		—			(40	)		—
Litigation settlements		—			108			—
Gain on sale of Premcor-Valero shares		—			—			726
State tax issue charge ^(a)		—			—			(10	)
Settlement of federal tax issue ^(a)		—			—			619
Reversal of tax reserves ^(a)		—			—			335
Equity investment impairment		—			—			(15	)
Equity investment hurricane insurance
charge		—			—			(2	)
Hurricane insurance charge		—			—			(10	)
Tax effect of pre-tax adjustments		(2	)		(41	)		(219	)
Discontinued operations, net of tax ^(a)		322			(11	)		452
Cumulative effect of changes in
accounting principles, net of tax ^(a)		—			—			3
Total Corporate and Other	$	407		$	75		$	1,977

(a)	Amounts shown after tax.

TAXES

Deferred tax liabilities, net of deferred tax assets of $1.7 billion, were $2.1 billion at December 31, 2007. The current portion of the deferred tax assets of $230 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 income from continuing operations:

In millions	2007			2006			2005
EARNINGS
Oil and Gas ^(a)	$	8,318		$	6,880		$	5,662
Chemical		601			906			614
Corporate and Other ^(b)		(334	)		(230	)		403
Pre-tax income ^(a)		8,585			7,556			6,679
Income tax expense
Federal and State		1,558			1,625			592
Foreign ^(a)		1,949			1,729			1,249
Total		3,507			3,354			1,841
Income from continuing operations	$	5,078		$	4,202		$	4,838
Worldwide effective tax rate		41%			44%			28%

(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 $1.3 billion, $1.1 billion and $887 million for the years ended December 31, 2007, 2006 and 2005, respectively.
(b)	The 2005 amount includes a $726 million pre-tax gain from Valero's acquisition of Premcor Inc. (Premcor) and the subsequent sale of all of the Valero shares received.

Occidental’s 2007 worldwide effective tax rate was 41 percent. The decrease in the income tax rate in 2007, compared to 2006, resulted from lower taxes on the 2007 sale of certain properties.

Occidental's 2006 worldwide effective tax rate was 44 percent. 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	2007		2006		2005
Net sales	$	18,784	$	17,175	$	14,153
Interest, dividends and other income	$	355	$	381	$	181
Gains on disposition of assets, net	$	874	$	118	$	870

The increase in net sales in 2007, compared to 2006, reflects higher crude oil prices and increased oil and gas production, including production from the start-up of the Dolphin Project in the third quarter of 2007.

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.

Interest, dividends and other income of 2007 includes $112 million of gains from litigation settlements.

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.

Gains on disposition of assets, net in 2007, includes a $326 million gain from the sale of 21 million shares of Lyondell, a $412 million gain from the sale of Occidental’s interest in a Russian joint venture and a gain of $103 million from the sale of exploration properties in West Africa.

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

Gains on disposition of assets, net in 2005 include 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	2007		2006		2005
Cost of sales ^(a)	$	6,627	$	6,192	$	5,336
Selling, general and administrative
and other operating expenses	$	1,561	$	1,356	$	1,310
Depreciation, depletion and
amortization	$	2,379	$	2,008	$	1,372
Exploration expense	$	422	$	296	$	310
Interest and debt expense, net	$	339	$	291	$	293

(a)	Excludes depreciation, depletion and amortization of $2,338 million in 2007, $1,978 million in 2006 and $1,334 million in 2005.

Cost of sales increased in 2007, compared to 2006, due to higher crude oil and natural gas production and maintenance costs and higher chemicals feedstock costs.

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

Selling, general and administrative and other operating expenses increased in 2007, compared to 2006, due to 2007 severance charges, higher production taxes and higher stock-based and incentive compensation expense. The increase in stock-based and incentive compensation expense in 2007, compared to 2006, resulted from a 58-percent increase in Occidental's stock price and higher net income, which increased the performance measures used to value certain of the existing stock-based awards, partially offset by a decrease in the value of awards granted in 2007.

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

DD&A increased in 2007, compared to 2006, due to increased production, mainly from the Dolphin Project, and higher costs of new reserve additions resulting in a higher DD&A rate.

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.

The increase in exploration expense in 2007, compared to 2006, was due to increases in the Colombia and Middle East/North Africa exploration programs and impairments in California.

Interest and debt expense in 2007, 2006 and 2005 included pre-tax debt repayment expenses of $167 million, $35 million and $42 million, respectively. Excluding the effect of these debt repayment charges, interest expense decreased in 2007, compared to 2006, due to lower debt levels and lower effective interest rates.

Selected Other Items

In millions	2007			2006			2005
Provision for income taxes	$	3,507		$	3,354		$	1,841
Income from equity investments	$	(82	)	$	(183	)	$	(232	)
Discontinued operations, net	$	322		$	(11	)	$	452

The increase in the provision for income taxes in 2007, compared to 2006, was due to an increase in income before taxes in 2007.

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 2007, compared to 2006, was due to the sale of Occidental’s interest in Lyondell and a Russian joint venture.

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.

Discontinued operations in 2007 include after-tax income of $326 million for the operations of Horn Mountain and Pakistan that were sold as part of a series of transactions with BP as well as the results of operations of these assets before disposal.

Discontinued operations in 2006 include a $296 million after-tax loss for Ecuador after Occidental's contract for its Block 15 operations was terminated in May 2006. The 2006 amount also includes $285 million after-tax income for the operations of Horn Mountain and Pakistan as well as the Vintage assets that were held for sale.

Discontinued operations in 2005 include after-tax income from Ecuador, Horn Mountain and Pakistan operations.

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	2007		2006
CURRENT ASSETS
Cash and cash equivalents	$	1,964	$	1,339
Short-term investments		—		240
Trade receivables, net		4,973		2,825
Receivables from joint ventures, partnerships
and other		416		499
Inventories		910		825
Prepaid expenses and other		332		257
Assets of discontinued operations		—		184
Total current assets	$	8,595	$	6,169
Investments in unconsolidated entities	$	783	$	1,344
Property, plant and equipment, net	$	26,278	$	24,138
CURRENT LIABILITIES
Current maturities of long-term debt and notes
payable	$	47	$	171
Accounts payable		4,263		2,263
Accrued liabilities		1,399		1,532
Dividends payable		212		188
Domestic and foreign income taxes		227		396
Liabilities of discontinued operations		118		145
Total current liabilities	$	6,266	$	4,695
Long-term debt, net	$	1,741	$	2,619
Deferred credits and other liabilities-income taxes	$	2,324	$	2,366
Deferred credits and other liabilities-other	$	3,156	$	2,952
Long-term liabilities of discontinued operations	$	174	$	195
Minority interest	$	35	$	352
Stockholders’ equity	$	22,823	$	19,252

Assets

See "Cash Flow Analysis" for discussion about the change in cash and cash equivalents.

The decrease in short-term investments was due to the sale of Occidental's investments in auction rate securities. The increase in trade receivables, net was due to higher crude oil and natural gas prices and volumes during the fourth quarter of 2007 compared to 2006. The decrease in receivables from joint ventures, partnerships and other was due to mark-to-market adjustments on derivative instruments. The increase in inventories was due to an increase in materials and supplies, mainly in Colombia and Libya, and higher purchases from third parties in the marketing and trading operations. The increase in prepaid expense and other was due to increases in current deferred tax assets and higher prepaid insurance premiums. The decrease in assets of discontinued operations was due to the sale of Pakistan operations and an exchange involving the Horn Mountain operations with BP during 2007.

The decrease in investments in unconsolidated entities was due to the sale of 21 million shares of Lyondell and the sale of Occidental’s interest in a Russian joint venture. The increase in property, plant and equipment (PP&E), net was due to capital expenditures in 2007 and various oil and gas acquisitions, offset by 2007 DD&A and sales of various oil and gas assets.

Liabilities and Stockholders' Equity

The increase in accounts payable was due to higher prices and volumes for purchased crude oil and natural gas in the marketing and trading operations. In 2007, the decrease in accrued liabilities was due to contract bonus payments in Oman, contingent payments related to acquisitions and 2006 accruals for interest that were paid for in the debt tender offers. The decrease in domestic and foreign income taxes was due to the adoption of Financial Accounting Standards Board (FASB) Interpretation (FIN) 48.

The decrease in long-term debt, net was due to the January 2007 debt repurchases under cash tender offers, the May 2007 redemption of the Vintage senior notes due 2012 and required debt payments. The increase in deferred credits and other liabilities – other was due to an increase in asset retirement obligations and higher mark-to-market adjustments on derivative instruments. The decrease in minority interest was due to Occidental's purchase of the minority interest in a chemical operation from a third party.

The increase in stockholders' equity reflects net income for 2007 partially offset by treasury stock repurchases of approximately 20.6 million shares in 2007 and dividend payments.

LIQUIDITY AND CAPITAL RESOURCES

At December 31, 2007, Occidental had approximately $2.0 billion in cash on hand. Although income and cash flows are largely dependent on oil and gas prices and production, Occidental believes that cash on hand and cash generated from operations will be sufficient to fund its operating needs, capital expenditure requirements, dividend payments, anticipated acquisitions, debt payments and purchases under its announced common stock repurchase program. If needed, Occidental could access its existing credit facilities.

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. In September 2007, participating lenders extended the maturity date on $1.4 billion of aggregate loan commitments under the Credit Facility to September 2012. 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 did not draw down any amounts under the Credit Facility during 2007. Available but unused lines of committed bank credit totaled approximately $1.5 billion at December 31, 2007.

At December 31, 2007, under the most restrictive covenants of certain financing agreements, Occidental's capacity for additional unsecured borrowing was approximately $54.8 billion, and the capacity for the payment of cash dividends and other distributions on, and for acquisitions of, Occidental's capital stock was approximately $20.8 billion, assuming that such dividends, distributions and acquisitions were made without incurring additional borrowing.

In May 2007, Occidental redeemed all $276 million of the outstanding principal amount of its 8.25-percent Vintage Petroleum, LLC (Vintage) senior notes due 2012. In January 2007, Occidental completed cash tender offers for its 10.125-percent senior debentures due 2009, 9.25-percent senior debentures due 2019, 8.75-percent medium-term 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 in principal amount. The redemption and repurchases resulted in a pre-tax interest expense of $167 million.

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, 2007, no securities had been issued under this shelf.

Cash Flow Analysis

In millions	2007		2006		2005
Net cash provided by operating
activities	$	6,798	$	6,353	$	5,337

The increase in operating cash flow in 2007, compared to 2006, resulted from higher crude oil prices and higher oil and gas production partially offset by the effects of lower chemical margins, particularly PVC, and reduced cash flow from discontinued operations. In 2007, Occidental’s realized crude oil prices increased 12 percent and its oil and gas production increased by over 4 percent compared to 2006. The increase in production was mainly due to the start-up of the Dolphin Project production in the third quarter of 2007.

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

Most major chemical prices, especially PVC, decreased in 2007, compared to 2006, which reduced chemical margins. The overall impact of the chemical price decreases on cash flow was much less significant than the increase in crude oil prices because the chemical segment earnings and cash flow are significantly smaller that those for the oil and gas segment.

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 17 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. 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.

Other non-cash charges to income in 2007 included deferred compensation, stock incentive plan amortization and environmental remediation accruals. 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.

In millions		2007			2006			2005
Net cash used by investing activities		$	(3,128	)	$	(4,383	)	$	(3,161	)

The 2007 amount includes cash proceeds of $672 million from the sale of 21 million shares of Lyondell, $485 million received from the sale of Occidental’s interest in a Russian joint venture, $509 million from the sale of other businesses and properties, and $250 million from the sale of auction rate securities. The 2007 amount also includes the cash paid for the acquisitions of various oil and gas and chemical interests, a Permian Basin common carrier pipeline system and a gas processing plant in Texas totaling $1.4 billion.

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.

Also, see the "Capital Expenditures" section below.

In millions		2007			2006			2005
Net cash used by financing activities		$	(3,045	)	$	(2,819	)	$	(1,187	)

The 2007 amount includes net debt payments of $1.2 billion, including the repurchase of various debt issues under cash tender offers and the redemption of the Vintage senior notes due 2012. The 2007 amount also included $1.1 billion of cash paid for repurchases of 20.6 million shares of Occidental’s common stock at an average price of $54.75 per share.

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.

Occidental paid common stock dividends of $765 million in 2007, $646 million in 2006 and $483 million in 2005.

Capital Expenditures

In millions	2007		2006		2005
Oil and Gas	$	3,206	$	2,703	$	2,108
Chemical		251		251		173
Corporate and Other		40		33		14
Total ^(a)	$	3,497	$	2,987	$	2,295

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

Occidental’s capital spending estimate for 2008 is approximately $3.8 to $3.9 billion. Most of the capital spending increase will be allocated to oil and gas exploration, production and development activities for the Colombia LCI project and the Vintage properties in Argentina and California.

Commitments at December 31, 2007, for major capital expenditures during 2008 and thereafter were approximately $330 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 generally accepted accounting principles (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" for further information about the structure of the Dolphin Project.

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 through April 2008 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 facility to fund the construction of a certain portion of the Dolphin Project. Occidental guarantees 24.5 percent of both of these obligations of Dolphin Energy. At December 31, 2007, Occidental’s portion of the bridge loan and financing facility was $816 million. Occidental had recorded $588 million on the balance sheet at December 31, 2007, for the combined bridge loan and financing facility. The remaining amounts of the bridge loan and financing facility drawdowns are discussed in the "Guarantees" section below.

Ecuador

In Ecuador, Occidental has a 14-percent interest in the Oleoducto de Crudos Pesados Ltd. (OCP) oil export pipeline. As of December 31, 2007, Occidental’s net investment in and advances to the project totaled $69 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, which 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, which has not been exercised to date. At December 31, 2007, the total pre-tax advance tariff of approximately $89 million was accrued in Occidental’s consolidated financial statements. This advance tariff would be used by the pipeline company to service or prepay project debt. At December 31, 2007, 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. For more information, 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, 2007, the notional amount of the guarantees that are subject to the reporting requirements of FIN 45 was approximately $250 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, 2007 and/or disclosed in the accompanying Notes.

			Payments Due by Year
Contractual Obligations (in millions)	Total		2008		2009 to 2010		2011 to 2012		2013 and thereafter
Consolidated
Balance Sheet
Long-term debt
(Note 5) ^(a)	$	1,777	$	35	$	923	$	436	$	383
Capital leases
(Note 6)		37		1		2		2		32
Other liabilities ^(b)		7,468		5,618		713		412		725
Other Obligations
Operating leases
(Note 6) ^(c)		1,305		207		229		151		718
Purchase
obligations ^{(d, e)}		6,980		2,145		2,253		1,430		1,152
Total	$	17,567	$	8,006	$	4,120	$	2,431	$	3,010

(a)	Excludes unamortized debt discount and interest expense on the debt. As of December 31, 2007, interest on long-term debt totaling $767 million is payable in the following years (in millions): 2008 - $105, 2009 to 2010 - $149, 2011 to 2012 - $112 and 2013 and thereafter - $401.
(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. Long-term material purchase contracts are discounted using a 6.4-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, 23 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. In September 2007, the plaintiffs in the Osorio case filed an action in state court in Florida seeking to enforce the Nicaraguan judgment. That action was removed to and is presently pending in federal court. 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 and state corporate income tax purposes. Corporate tax returns for taxable years 2001 through the current year 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, 2007, 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 $52 million, which was payable as follows (in millions): 2008 – $12, 2009 – $10, 2010 – $10, 2011 – $9, 2012 – $8 and thereafter – $3. Fixed payments under these agreements were $18 million in 2007, $18 million in 2006 and $17 million in 2005. 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 $3.8 to $3.9 billion in capital expenditures estimated for 2008.

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, 2007, 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 participate in environmental assessments and cleanups under these laws at currently-owned facilities, previously-owned sites and third-party 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, local and foreign environmental laws. These proceedings seek funding or performance of remediation and, in some cases, compensation for alleged property damage, punitive damages and civil penalties.

As of December 31, 2007, Occidental, through a wholly owed subsidiary, participated in or monitored ongoing or recent assessments, remediation, proceedings or information requests at 163 sites. Thirty-nine of those sites are currently listed or proposed for listing by the U.S. Environmental Protection Agency on the National Priorities List.

The following table presents Occidental’s environmental remediation reserves at December 31, 2007, 2006 and 2005, grouped by three categories of environmental remediation sites:

$ amounts in millions	2007			2006			2005
	# of Sites	Reserve Balance		# of Sites	Reserve Balance		# of Sites	Reserve Balance
CERCLA &
equivalent sites	105	$	225	105	$	226	128	$	236
Active facilities	17		99	21		116	18		114
Closed or sold
facilities	41		133	40		70	39		68
Total	163	$	457	166	$	412	185	$	418

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

In millions	2007			2006			2005
Balance - Beginning of Year	$	412		$	418		$	375
Remediation expenses
and interest accretion		108			48			63
Changes from acquisitions		5			17			45
Payments		(68	)		(71	)		(71	)
Other		—			—			6
Balance - End of Year	$	457		$	412		$	418

Occidental expects to expend funds equivalent to about half of the current environmental reserve over the next four 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 $400 million beyond the amount accrued.

For management’s opinion with respect to environmental matters, refer to the "Lawsuits, Claims, Commitments, Contingencies and Related Matters" section above.

CERCLA and Equivalent Sites

As of December 31, 2007, OPC or certain of its subsidiaries have been named in 105 CERCLA or equivalent proceedings, as shown below.

Description ($ amounts in millions)	# of Sites	Reserve Balance
Minimal/No exposure ^(a)	85	$	7
Reserves between $1-10 MM	14		47
Reserves over $10 MM	6		171
Total	105	$	225

(a)

Includes 30 sites for which Maxus Energy Corporation has retained the liability and indemnified Occidental, 6 sites where Occidental has denied liability without challenge, 31 sites where Occidental’s reserves are less than $50,000 each, and 18 sites where reserves are between $50,000 and $1 million each.

The six sites with individual reserves over $10 million in 2007 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 17 active facilities. Four assets — a chemical plant in Louisiana, a chemical plant in Kansas and certain oil and gas properties and pipeline systems in the southwestern United States — account for 69 percent of the reserves associated with these facilities.

Closed or Sold Facilities

There are 41 other sites formerly owned or operated by certain subsidiaries of OPC that have ongoing environmental remediation requirements in which OPC or its subsidiaries are involved. Four sites account for 70 percent of the reserves associated with this group. The four 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 chemical plant in Pennsylvania and a former phosphorous processing and recovery facility in Tennessee.

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	2007		2006		2005
Operating Expenses
Oil and Gas	$	108	$	95	$	65
Chemical		80		73		67
	$	188	$	168	$	132
Capital Expenditures
Oil and Gas	$	59	$	55	$	43
Chemical		14		25		21
	$	73	$	80	$	64
Remediation Expenses
Corporate	$	107	$	47	$	62

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 $91 million for 2008 and $93 million for 2009.

FOREIGN INVESTMENTS

Portions of Occidental’s assets are located outside of North America. At December 31, 2007, the carrying value of Occidental’s assets in countries outside North America aggregated approximately $10.0 billion, or approximately 28 percent of Occidental’s total assets at that date. Of such assets, approximately $5.9 billion are located in the Middle East/North Africa and approximately $4.1 billion are located in Latin America. For the year ended December 31, 2007, net sales outside North America totaled $6.3 billion, or approximately 33 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 differing from those estimated when the reserves were initially recorded. Occidental's revisions to proved reserves were negative for 2007 and amounted to approximately 3 percent of the total reserves for the year. 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. Occidental's revisions to proved reserves have been positive for seven of the last ten years. Additionally, Occidental is required to perform impairment tests pursuant to Statement of Financial Accounting Standards (SFAS) No. 144, generally when prices decline other than temporarily, reserve estimates change significantly or other significant events occur that may impact the ability to realize the recorded asset amounts.

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 $9.61 per barrel to $9.13 per barrel, which would increase pre-tax income by $100 million annually. A 5-percent decrease in the oil and gas reserves would change the rate from $9.61 per barrel to $10.09 per barrel and would result in a decrease in pre-tax income of $100 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, 2007, the capitalized costs attributable to unproved properties, net of accumulated valuation allowance, were $1.4 billion. 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.

Occidental performs impairment tests on its assets, per SFAS No. 144, 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's net PP&E for chemicals is approximately $2.6 billion and its depreciation expense for 2008 is expected to be approximately $320 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 $16 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, 2007 and 2006, 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 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; or

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 $46 million. If the reserve balance were to increase by 10 percent, Occidental would record an additional remediation expense of $46 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.

Future Accounting Changes

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.

SFAS No. 159

In February 2007, the FASB issued SFAS No. 159, "The Fair Value Option for Financial Assets and Financial Liabilities." This statement provides entities the option to measure certain financial instruments at fair value. SFAS No. 159 is effective for financial statements issued for fiscal years beginning after November 15, 2007. Occidental is currently assessing the effect of SFAS No. 159 on its financial statements.

EITF Issue No. 07-1

In December 2007, the FASB finalized the provisions of the Emerging Issues Task Force (EITF) Issue No. 07-1, "Accounting for Collaborative Arrangements." This EITF Issue provides guidance and requires financial statement disclosures for collaborative arrangements. EITF Issue No. 07-1 is effective for financial statements issued for fiscal years beginning after December 15, 2008. Occidental is currently assessing the effect of EITF Issue No. 07-1 on its financial statements but it is not expected to be material.

SFAS No. 141(R)

In December 2007, FASB issued SFAS No. 141(R), "Business Combinations." This statement provides new accounting guidance and disclosure requirements for business combinations. SFAS No. 141(R) is effective for business combinations which occur in the first fiscal year beginning on or after December 15, 2008.

SFAS No. 160

In December 2007, FASB issued SFAS No. 160, "Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB No. 51." This statement provides new accounting guidance and disclosure and presentation requirements for noncontrolling interests in a subsidiary. SFAS No. 160 is effective for the first fiscal year beginning on or after December 15, 2008. Occidental is currently assessing the effect of SFAS No. 160 on its financial statements.

Recently Adopted Accounting Changes

FIN No. 48

In June 2006, the FASB issued FIN No. 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. Occidental adopted FIN No. 48 on January 1, 2007.

The following table shows the effect of adopting FIN No. 48 on the consolidated balance sheet at January 1, 2007 (in millions):

	Debit/(Credit)
Domestic and foreign income taxes – Current	$	140
Deferred and other domestic and foreign income taxes	$	(8	)
Deferred credits and other liabilities – Other	$	100
Minority interest	$	(13	)
Retained earnings	$	(219	)

FSP AUG AIR-1

In September 2006, the FASB issued FASB Staff Position (FSP) AUG AIR-1, "Accounting for Planned Major Maintenance Activities," which is effective for the first fiscal year beginning after December 15, 2006. This FSP prohibits the use of the accrue-in-advance method of accounting for planned major maintenance activities, which was used by certain operations of Occidental. When Occidental adopted FSP AUG AIR-1 on January 1, 2007, those operations changed to the deferral method of accounting for planned major maintenance activities. The adoption of FSP AUG AIR-1 was retrospectively applied to all periods presented and the impact to the income statements for the years ended December 31, 2006 and 2005 was immaterial.

The following table shows the effects of adopting FSP AUG AIR-1 on the consolidated balance sheet at January 1, 2007 (in millions):

	Debit/(Credit)
Prepaid expenses and other	$	1
Property, plant and equipment, net	$	(16	)
Other assets	$	91
Accrued liabilities	$	43
Deferred and other domestic and foreign income taxes	$	(40	)
Minority interest	$	(11	)
Retained earnings	$	(68	)

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.

DERIVATIVE ACTIVITIES AND MARKET RISK

General

Occidental's market risk exposures relate primarily to commodity prices. Occidental has entered into derivative instrument transactions to reduce these price 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 $151 million. If domestic natural gas prices vary by $0.50 per Mcf, it would have an estimated annual effect on pre-tax income of approximately $96 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 a pre-tax annual effect on income of approximately $15 million and $30 million, respectively. If PVC prices vary by $.01/lb, it would have a pre-tax annual effect on income of approximately $30 million. If ethylene dichloride (EDC) prices vary by $10/ton, it would have a pre-tax annual effect on income of approximately $5 million. Historically, product price changes either precede or follow raw material and feedstock product price changes; therefore, the margin improvement of price changes can be mitigated. According to Chemical Market Associates, Inc., December 2007 average contract prices were: chlorine—$323/ton, caustic soda—$498/ton, PVC—$0.67/lb and EDC—$310/ton.

Marketing and Trading Operations

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 President and 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 2007 and 2006, and segregate the open contracts at December 31, 2007 by maturity periods.

In millions	2007			2006
Fair value of contracts outstanding at
beginning of year – unrealized losses	$	(355	)	$	(457	)
Losses on contracts realized or otherwise
settled during the year		106			106
Changes in fair value attributable to changes in
valuation techniques and assumptions		—			—
Losses or other changes in fair value		(327	) ^(a)		(4	)
Fair value of contracts outstanding at end of
year – unrealized losses	$	(576	)	$	(355	)

(a)	Primarily relates to price changes on existing production hedges.

	Maturity Periods
Source of Fair Value – unrealized (losses) gains	2008			2009 to 2010			2011 to 2012			2013 and thereafter			Total Fair Value
Prices actively quoted	$	131		$	7		$	4		$	2		$	144
Prices provided by
other external
sources		1			3			(3	)		(2	)		(1	)
Prices based on
models and other
valuation methods ^(a)		(233	)		(337	)		(149	)		—			(719	)
Total	$	(101	)	$	(327	)	$	(148	)	$	—		$	(576	)

(a)	The underlying prices utilized for the fair value calculations of the options are based on monthly NYMEX published prices. 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 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. The fixed price swaps and the basis swaps expired in 2007. The collar agreements continue to the end of 2011. The 2007 volume that was hedged was less than 3 percent of Occidental’s 2007 crude oil and natural gas production. Information about these cash-flow hedges, which are included in the total fair value of ($576) million in the table above, is presented in a tabular presentation below as of December 31, 2007 (volumes in thousands of barrels):

	Crude Oil – Collars
	Daily Volume	Average Floor	Average Cap
2008	14	$34.07	$47.47
2009	13	$33.15	$47.41
2010	12	$33.00	$46.35
2011	12	$32.92	$46.27

($ millions)		Crude Oil – Collars
Fair value liability		($715)

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 2007.

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 and $21 million for the years ended December 31, 2006 and 2005, respectively.

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)
2008	$	35	$	—	$	35
2009		96		588		684
2010		239		—		239
2011		—		68		68
2012		368		—		368
2013		—		—		—
Thereafter		337		46		383
Total	$	1,075	$	702	$	1,777
Average interest rate		7.10%		5.35%		6.41%
Fair Value	$	1,189	$	702	$	1,891

(a)	Excludes unamortized net discounts of $1 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 in foreign currencies 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, 2007 and 2006, Occidental had not entered into any foreign currency derivative instruments. The effect of exchange rates on 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," "would," "could," "may," "might," "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 and subsidiaries (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, 2007 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, 2007, Occidental’s system of internal control over financial reporting is effective.

Occidental’s independent auditors, KPMG LLP, have issued an attestation report on 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 as of December 31, 2007 and 2006, 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, 2007. 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, 2007 and 2006, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2007, 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 January 1, 2007, the Company changed its method of accounting for uncertain tax positions; effective December 31, 2006, the Company changed its method of accounting for defined benefit pension and other postretirement plans; and 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), Occidental Petroleum Corporation and subsidiaries’ internal control over financial reporting as of December 31, 2007, 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 22, 2008 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/ KPMG LLP

Los Angeles, California

February 22, 2008

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 Occidental Petroleum Corporation and subsidiaries' internal control over financial reporting as of December 31, 2007, 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, included in the accompanying Management’s Annual Assessment of and Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on 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, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included 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, Occidental Petroleum Corporation and its subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, 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, 2007 and 2006, 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, 2007, and our report dated February 22, 2008 expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

Los Angeles, California

February 22, 2008

Consolidated Statements of Income

In millions, except per-share amounts

Occidental Petroleum Corporation

and Subsidiaries

For the years ended December 31,	2007			2006			2005
REVENUES
Net sales	$	18,784		$	17,175		$	14,153
Interest, dividends and other income		355			381			181
Gains on disposition of assets, net		874			118			870
		20,013			17,674			15,204
COSTS AND OTHER DEDUCTIONS
Cost of sales (excludes depreciation, depletion and amortization of
$2,338 in 2007, $1,978 in 2006 and $1,334 in 2005)		6,627			6,192			5,336
Selling, general and administrative and other operating expenses		1,561			1,356			1,310
Depreciation, depletion and amortization		2,379			2,008			1,372
Environmental remediation		107			47			62
Exploration expense		422			296			310
Interest and debt expense, net		339			291			293
		11,435			10,190			8,683
INCOME BEFORE TAXES AND OTHER ITEMS		8,578			7,484			6,521
Provision for domestic and foreign income and other taxes		3,507			3,354			1,841
Minority interest		75			111			74
Income from equity investments		(82	)		(183	)		(232	)
INCOME FROM CONTINUING OPERATIONS		5,078			4,202			4,838
Discontinued operations, net		322			(11	)		452
Cumulative effect of changes in accounting principles, net		—			—			3
NET INCOME	$	5,400		$	4,191		$	5,293
BASIC EARNINGS PER COMMON SHARE
Income from continuing operations	$	6.08		$	4.93		$	6.00
Discontinued operations, net		0.39			(0.01	)		0.56
BASIC EARNINGS PER COMMON SHARE	$	6.47		$	4.92		$	6.56
DILUTED EARNINGS PER COMMON SHARE
Income from continuing operations	$	6.05		$	4.88		$	5.91
Discontinued operations, net		0.39			(0.01	)		0.56
DILUTED EARNINGS PER COMMON SHARE	$	6.44		$	4.87		$	6.47
DIVIDENDS PER COMMON SHARE	$	0.94		$	0.80		$	0.645

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,	2007			2006
CURRENT ASSETS
Cash and cash equivalents	$	1,964		$	1,339
Short-term investments		—			240
Trade receivables, net of reserves of $35 in 2007 and $15 in 2006		4,973			2,825
Receivables from joint ventures, partnerships and other		416			499
Inventories		910			825
Prepaid expenses and other		332			257
Assets of discontinued operations		—			184
Total current assets		8,595			6,169
LONG-TERM RECEIVABLES, NET		203			231
INVESTMENTS IN UNCONSOLIDATED ENTITIES		783			1,344
PROPERTY, PLANT AND EQUIPMENT
Oil and gas segment, successful efforts method		33,951			29,696
Chemical segment		5,049			5,063
Corporate and other		916			721
		39,916			35,480
Accumulated depreciation, depletion and amortization		(13,638	)		(11,342	)
		26,278			24,138
OTHER ASSETS		660			549
TOTAL ASSETS	$	36,519		$	32,431

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,	2007			2006
CURRENT LIABILITIES
Current maturities of long-term debt and notes payable	$	47		$	171
Accounts payable		4,263			2,263
Accrued liabilities		1,399			1,532
Dividends payable		212			188
Domestic and foreign income taxes		227			396
Liabilities of discontinued operations		118			145
Total current liabilities		6,266			4,695
LONG-TERM DEBT, NET OF CURRENT MATURITIES AND UNAMORTIZED NET DISCOUNT/PREMIUM		1,741			2,619
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred and other domestic and foreign income taxes		2,324			2,366
Long-term liabilities of discontinued operations		174			195
Other		3,156			2,952
		5,654			5,513
CONTINGENT LIABILITIES AND COMMITMENTS
MINORITY INTEREST		35			352
STOCKHOLDERS' EQUITY
Common stock, $.20 par value; authorized 1.1 billion shares;
outstanding shares: 2007 — 877,123,937 and 2006 — 870,678,608		175			174
Treasury stock: 2007 — 51,388,016 shares and 2006 — 30,760,490 shares		(2,610	)		(1,481	)
Additional paid-in capital		7,071			6,905
Retained earnings		18,819			13,987
Accumulated other comprehensive loss		(632	)		(333	)
		22,823			19,252
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	36,519		$	32,431

The accompanying notes are an integral part of these consolidated financial statements.

Consolidated Statements of Stockholders’ Equity

In millions

Occidental Petroleum Corporation

and Subsidiaries

													Accumulated
							Additional						Other
	Common			Treasury			Paid-in			Retained			Comprehensive
	Stock ^(a)			Stock			Capital ^(a)			Earnings ^(b)			Income(Loss)
Balance, December 31, 2004	$	159		$	—		$	4,572		$	5,711		$	155
Net income		—			—			—			5,293			—
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		$	10,484		$	(373	)
Net income		—			—			—			4,191			—
Pension and postretirement adjustments,
net of tax		—			—			—			—			(168	)
Other comprehensive income, net of tax		—			—			—			—			208
Dividends on common stock		—			—			—			(688	)		—
Issuance of common stock		11	^(c)		—			2,064	^(d)		—			—
Exercises of options and other, net		2			—			14			—			—
Purchases of treasury stock		—			(1,473	)		—			—			—
Balance, December 31, 2006	$	174		$	(1,481	)	$	6,905		$	13,987		$	(333	)
Net income		—			—			—			5,400			—
Uncertain tax positions adjustment		—			—			—			219			—
Other comprehensive loss, net of tax		—			—			—			—			(299	)
Dividends on common stock		—			—			—			(787	)		—
Issuance of common stock		—			—			94			—			—
Exercises of options and other, net		1			—			72			—			—
Purchases of treasury stock		—			(1,129	)		—			—			—
Balance, December 31, 2007	$	175		$	(2,610	)	$	7,071		$	18,819		$	(632	)

(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)	Restated to reflect adoption of FSP AUG AIR-1. See Note 3 for further information.
(c)	Amount represents stock issued for the Vintage acquisition.
(d)	Includes $2,054 for stock issued for the Vintage acquisition.

Consolidated Statements of Comprehensive Income

In millions

For the years ended December 31,	2007			2006			2005
Net income	$	5,400		$	4,191		$	5,293
Other comprehensive income(loss) items:
Foreign currency translation adjustments ^(a)		14			5			(13	)
Derivative mark-to-market adjustments ^(b)		(182	)		88			(330	)
Pension and postretirement adjustments ^(c)		(13	)		(3	)		(1	)
Reclassification of realized gains ^(d)		(217	)		(59	)		(463	)
Unrealized gains on securities ^(e)		99			177			279
Other comprehensive (loss) income, net of tax		(299	)		208			(528	)
Comprehensive income	$	5,101		$	4,399		$	4,765

(a)	Net of tax of $0, $0 and $13 in 2007, 2006 and 2005, respectively.
(b)	Net of tax of $103, $50 and $188 in 2007, 2006 and 2005, respectively.
(c)	Net of tax of $8, $1 and $0 in 2007, 2006 and 2005, respectively.
(d)	Net of tax of $124, $34 and $264 in 2007, 2006 and 2005, respectively. Amounts represent the recognition of the 2007 gain on the sale of the remaining Lyondell Chemical Company (Lyondell) shares, the 2006 gain on the partial sale of Lyondell shares and the 2005 gain due to Valero Energy Corporation’s (Valero) acquisition of Premcor, Inc. (Premcor) and the subsequent sale of the Valero shares.
(e)	Net of tax of $56, $102 and $165 in 2007, 2006 and 2005, 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,	2007			2006			2005
CASH FLOW FROM OPERATING ACTIVITIES
Net income	$	5,400		$	4,191		$	5,293
Adjustments to reconcile net income to net cash provided by operating activities:
Discontinued Operations, net		(322	)		11			(452	)
Cumulative effect of changes in accounting principles, net		—			—			(3	)
Depreciation, depletion and amortization of assets		2,379			2,008			1,372
Reversal of tax reserves		—			—			(954	)
Deferred income tax provision (benefit)		35			98			(54	)
Other noncash charges to income		887			588			812
Gains on disposition of assets, net		(874	)		(118	)		(870	)
Income from equity investments		(82	)		(183	)		(232	)
Dry hole and impairment expense		247			115			216
Changes in operating assets and liabilities:
Increase in accounts and notes receivable		(2,219	)		(85	)		(659	)
Increase in inventories		(71	)		(64	)		(126	)
Increase in prepaid expenses and other assets		(96	)		(161	)		(73	)
Increase (decrease) in accounts payable and accrued liabilities		1,807			(191	)		514
(Decrease) increase in current domestic and foreign income taxes		(73	)		(44	)		200
Other operating, net		(358	)		(234	)		(244	)
Operating cash flow from continuing operations		6,660			5,931			4,740
Operating cash flow from discontinued operations		138			422			597
Net cash provided by operating activities		6,798			6,353			5,337
CASH FLOW FROM INVESTING ACTIVITIES
Capital expenditures		(3,497	)		(2,987	)		(2,295	)
Sale of assets, net		509			982			185
Purchase of assets, net		(1,381	)		(2,545	)		(2,126	)
Purchase of short-term investments		(10	)		(177	)		(185	)
Sale of short-term investments		250			190			183
Sales of equity investments and available-for-sale investments		1,157			251			1,122
Equity investments and other, net		(145	)		(74	)		83
Investing cash flow from continuing operations		(3,117	)		(4,360	)		(3,033	)
Investing cash flow from discontinued operations		(11	)		(23	)		(128	)
Net cash used by investing activities		(3,128	)		(4,383	)		(3,161	)
CASH FLOW FROM FINANCING ACTIVITIES
Proceeds from long-term debt		127			173			236
Payments of long-term debt and capital lease liabilities		(1,291	)		(1,066	)		(1,134	)
Proceeds from issuance of common stock		17			7			13
Purchases of treasury stock		(1,129	)		(1,473	)		(8	)
Redemption of preferred stock		(75	)		—			—
Cash dividends paid		(765	)		(646	)		(483	)
Stock options exercised		28			46			126
Excess tax benefits related to share-based payments		43			140			36
Other financing, net		—			—			28
Financing cash flow from continuing operations		(3,045	)		(2,819	)		(1,186	)
Financing cash flow from discontinued operations		—			—			(1	)
Net cash used by financing activities		(3,045	)		(2,819	)		(1,187	)
Increase (Decrease) in cash and cash equivalents		625			(849	)		989
Cash and cash equivalents — beginning of year		1,339			2,188			1,199
Cash and cash equivalents — end of year	$	1,964		$	1,339		$	2,188

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 this report, 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 affiliates and chemical subsidiaries and affiliates. The subsidiaries and other affiliates in the oil and gas segment explore for, develop, produce and market crude oil, natural gas liquids (NGL) 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 stockholders 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 2007 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 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. Certain incentive programs may 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 $1.7 billion as of December 31, 2007, 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 $10.0 billion as of December 31, 2007, and net sales of approximately $6.3 billion for the year ended December 31, 2007, 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 $2.0 billion and $1.3 billion at December 31, 2007 and 2006, respectively.

SHORT-TERM INVESTMENTS

Occidental’s short-term investments consist of highly liquid debt securities (auction-rate 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/loss (AOCI). Occidental sold all of its short-term investments in 2007.

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. Crude oil and 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 16).

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

In millions	2007			2006			2005
Balance — Beginning of Year	$	46		$	46		$	5
Additions to capitalized exploratory well costs pending the determination of proved
reserves		18			24			46
Reclassifications to property, plant and equipment based on the determination of
proved reserves		(5	)		(23	)		(2	)
Capitalized exploratory well costs charged to expense		(42	)		(1	)		(3	)
Balance — End of Year	$	17		$	46		$	46

Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and NGLs that geological and engineering data demonstrate, with reasonable certainty, can be recovered in future years from known reservoirs under existing economic and operating conditions considering future production and development costs. Depreciation and depletion of oil and gas producing properties is determined by the unit-of-production method.

The carrying value of Occidental’s property, plant and equipment (PP&E) is based on the cost incurred to acquire the PP&E, net of accumulated depreciation, 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 is attributable to unproved properties. At December 31, 2007, the net capitalized costs attributable to unproved properties were $1.4 billion. During 2007, approximately $190 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 assets, per Statement of Financial Accounting Standards (SFAS) No. 144, 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.

In 2005, 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 $288 million and $277 million at December 31, 2007 and 2006, 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 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; or

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 $445 million and $346 million is included in deferred credits and other liabilities - other, with the remaining current portion in accrued liabilities at December 31, 2007 and 2006, respectively.

For the years ended December 31, (in millions)	2007			2006
Beginning balance	$	362		$	222
Liabilities incurred		31			33
Liabilities settled		(17	)		(13	)
Accretion expense		23			19
Acquisitions and other		9			62
Revisions to estimated cash flows		63			39
Ending balance	$	471		$	362

DERIVATIVE INSTRUMENTS

All derivative instruments required to be marked-to-market under 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), performance restricted share units (PRSUs) and cash-settled share units (CSSUs), 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), performance stock awards (PSAs) and total shareholder return incentives (TSRIs), compensation expense is measured on the grant date using valuation models. Compensation expense for RSUs, PRSUs, Options, stock-settled SARs, CSSUs, PSAs and TSRIs, 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 and TSRIs, 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. For CSSUs, changes in fair value of the market price of Occidental common stock between the grant date and the date of vesting are 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 for continuing operations, net of refunds, during the years 2007, 2006 and 2005 included federal, foreign and state income taxes of approximately $2.177 billion, $2.130 billion and $1.736 billion, respectively. Net cash payments for federal, foreign and state income taxes paid by discontinued operations during the years 2007, 2006 and 2005 were $17 million, $102 million and $108 million, respectively. Interest paid (net of interest capitalized) totaled approximately $248 million, $211 million and $253 million for the years 2007, 2006 and 2005, 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 $18 million in 2007, zero in 2006 and $9 million in 2005.

NOTE 2 BUSINESS COMBINATIONS AND ASSET ACQUISITIONS AND DISPOSITIONS

2007

In January 2007, Occidental sold its 50-percent joint venture interest in Russia for an after-tax gain of approximately $412 million.

In June 2007, Occidental completed a fair value exchange under which BP p.l.c. (BP) acquired Occidental's oil and gas interests in Horn Mountain and received cash. Occidental acquired oil and gas interests in the Permian Basin and a gas processing plant in Texas from BP. Occidental also purchased for cash BP's west Texas pipeline system and, in a separate transaction, Occidental sold its oil and gas interests in Pakistan to BP. As a result of these transactions, both the Horn Mountain and Pakistan operations were classified as discontinued operations for all periods presented. Net revenues and pre-tax income for discontinued operations related to Pakistan and Horn Mountain were $193 million and $469 million (including after-tax disposal gains of $230 million) in 2007, $486 million and $359 million in 2006 and $444 million and $306 million in 2005. The assets and liabilities of Horn Mountain and Pakistan are classified as assets of discontinued operations and liabilities of discontinued operations on the consolidated balance sheet. At December 31, 2006, asset and liabilities of discontinued operations related to Horn Mountain and Pakistan were $162 million and $14 million, respectively, which were mainly comprised of PP&E and asset retirement obligations.

In September 2007, Occidental sold exploration properties in West Africa and recorded a pre-tax gain of $103 million.

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.

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, which were subsequently sold in 2006 for $1.0 billion with no gain or loss recorded. 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. 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	$	17,741	$	15,856
Net income	$	4,157	$	5,386
Basic earnings per common share	$	4.88	$	6.24
Diluted earnings per common share	$	4.83	$	6.16

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. 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 on a retrospective application basis. At December 31, 2007 and 2006, liabilities of discontinued operations related to Ecuador were $292 million and $321 million, respectively, which mainly consisted of the ship or pay obligations to the OCP pipeline. Net revenues and pre-tax income (loss) for discontinued operations related to Ecuador for the years ended December 31, 2006 and 2005 were $275 million and $(529) million, including a pre-tax write-off of $(673) million, and $611 million and $325 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, Occidental signed an agreement with the Libya National Oil Corporation which allowed it to re-enter the country and participate in exploration and production operations in the Sirte Basin, which it left in 1986 pursuant to United States law. This re-entry agreement allowed Occidental to return to its Libyan operations on generally the same terms in effect when activities were suspended. Occidental’s rights in the producing fields extend through 2009 and early 2010.

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.

NOTE 3 ACCOUNTING CHANGES

FUTURE ACCOUNTING CHANGES

SFAS No. 157

SFAS No. 159

EITF Issue No. 07-1

SFAS No. 141(R)

SFAS No. 160

RECENTLY ADOPTED ACCOUNTING CHANGES

FIN No. 48

FSP AUG AIR-1

The following table shows the effects of adopting FSP AUG AIR-1 on the consolidated balance sheet at January 1, 2007 (in millions):

	Debit/(Credit)
Prepaid expenses and other	$	1
Property, plant and equipment, net	$	(16	)
Other assets	$	91
Accrued liabilities	$	43
Deferred and other domestic and foreign income taxes	$	(40	)
Minority interest	$	(11	)
Retained earnings	$	(68	)

SFAS No. 158

NOTE 4 INVENTORIES

Inventories of approximately $190 million and $204 million were valued under the LIFO method at December 31, 2007 and 2006, respectively. Inventories consisted of the following:

Balance at December 31, (in millions)	2007			2006
Raw materials	$	92		$	70
Materials and supplies		349			304
Finished goods		571			525
		1,012			899
LIFO reserve		(102	)		(74	)
Total	$	910		$	825

NOTE 5 LONG-TERM DEBT

Long-term debt consisted of the following:

Balance at December 31, (in millions)	2007			2006
Occidental Petroleum Corporation
6.75% senior notes due 2012	$	368		$	368
4.25% medium-term senior notes due 2010		227			227
8.45% senior notes due 2029		116			328
9.25% senior debentures due 2019		116			265
10.125% senior debentures due 2009		96			222
7.2% senior debentures due 2028		82			200
8.75% medium-term notes due 2023		22			76
11.125% senior notes due 2010		12			12
8.1% medium-term notes due 2008		10			10
4% medium-term senior notes due 2007		—			146
		1,049			1,854
Subsidiary Debt
Dolphin Energy Ltd. loans due 2009 (5.78% as of December 31, 2007 and 5.76% as of
December 31, 2006) ^(a)		588			473
2.95% to 6.3% unsecured notes due 2008 through 2018		140			171
8.25% Vintage senior notes due 2012		—			276
		1,777			2,774
Less:
Unamortized (discount) premium, net		(1	)		16
Current maturities		(35	)		(171	)
Total	$	1,741		$	2,619

(a)	The Dolphin Energy Ltd. loans include Occidental’s portion of the bridge loan and financing facility.

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 paid an annual facility fee of 0.06 percent in 2007 on the total commitment amount, which was based on Occidental's senior debt ratings.

In May 2007, Occidental redeemed all $276 million outstanding principal amount of its 8.25-percent Vintage Petroleum, LLC (Vintage) senior notes due 2012. In January 2007, Occidental completed cash tender offers for its 10.125-percent senior debentures due 2009, 9.25-percent senior debentures due 2019, 8.75-percent medium-term 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 in principal amount. The redemption and repurchases resulted in a pre-tax interest expense of $167 million.

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, 2007, minimum principal payments on long-term debt subsequent to December 31, 2007, aggregated $1,777 million, of which $35 million is due in 2008, $684 million in 2009, $239 million in 2010, $68 million in 2011, $368 million in 2012, zero in 2013 and $383 million thereafter.

At December 31, 2007, under the most restrictive covenants of certain financing agreements, Occidental's capacity for additional unsecured borrowing was approximately $54.8 billion and the capacity for the payment of cash dividends and other distributions on, and for acquisitions of, Occidental’s capital stock was approximately $20.8 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, 2007 and 2006, were approximately $1.9 billion and $3.1 billion, respectively, compared with carrying values of approximately $1.8 billion and $2.8 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, 2007 and 2006. 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, 2007, future net minimum lease payments for capital and noncancelable operating leases (excluding oil and gas and other mineral leases, utilities, taxes, insurance and maintenance expense) were the following:

In millions	Capital			Operating		^(a)
2008	$	1		$	199
2009		1			112
2010		1			99
2011		1			77
2012		1			58
Thereafter		32			708
Total minimum lease payments		37		$	1,253
Less:
Imputed interest		(12	)
Present value of minimum capital lease payments, net of current portion	$	25

(a)	At December 31, 2007, sublease rental amounts included in the future operating lease payments totaled $52 million, as follows (in millions): 2008—$8, 2009—$10, 2010—$8, 2011—$8, 2012—$8 and thereafter—$10.

Rental expense for operating leases, net of sublease rental income, was $196 million in 2007, $199 million in 2006 and $141 million in 2005. Rental expense was net of sublease income of $7 million in 2007, 2006 and 2005, respectively.

NOTE 7 DERIVATIVE ACTIVITIES

Occidental's market risk exposures relate mainly to commodity prices. Occidental has entered into derivative instrument transactions to reduce these price 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	2007			2006
Fair value of contracts outstanding at beginning of year – unrealized losses	$	(355	)	$	(457	)
Losses on contracts realized or otherwise settled during the year		106			106
Changes in fair value attributable to changes in valuation techniques and assumptions		—			—
Losses or other changes in fair values ^(a)		(327	)		(4	)
Fair value of contracts outstanding at end of year – unrealized losses	$	(576	)	$	(355	)

(a)	Primarily relates to price changes on existing production hedges.

	Maturity Periods
Source of Fair Value – unrealized (losses) gains	2008			2009 to 2010			2011 to 2012			2013 and thereafter			Total Fair Value
Prices actively quoted	$	131		$	7		$	4		$	2		$	144
Prices provided by other external sources		1			3			(3	)		(2	)		(1	)
Prices based on models and other valuation methods ^(a)		(233	)		(337	)		(149	)		—			(719	)
Total	$	(101	)	$	(327	)	$	(148	)	$	—		$	(576	)

(a)	The underlying prices utilized for the fair value calculations of the options are based on monthly NYMEX published prices. These prices are entered into an industry standard options pricing model to determine fair value.

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 and $21 million for the years ended December 31, 2006 and 2005, respectively.

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)	2007		2006
Derivative financial instrument assets
Receivables from joint ventures, partnerships and other	$	177	$	248
Long-term receivables, net		35		61
	$	212	$	309
Derivative financial instrument liabilities
Accrued liabilities	$	278	$	291
Deferred credits and other liabilities – other		510		384
	$	788	$	675

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

In millions	2007			2006
Beginning Balance	$	(259	)	$	(347	)
Gains (losses) from changes in cash flow hedges		(243	)		32
Losses reclassified to income		61			56
Ending Balance	$	(441	)	$	(259	)

During the next twelve months, Occidental expects that approximately $114 million of net derivative after-tax losses included in AOCI, based on their valuation at December 31, 2007, will be reclassified into earnings. Hedge ineffectiveness did not have a material impact on earnings for the years ended December 31, 2007, 2006 and 2005.

NOTE 8 ENVIRONMENTAL LIABILITIES AND EXPENDITURES

ENVIRONMENTAL REMEDIATION

At December 31, 2007, Occidental, through a wholly owned subsidiary, participated in or monitored ongoing or recent assessments, remediation, proceedings or information requests at 163 sites. Thirty-nine of these sites are currently listed or proposed for listing by the U.S. Environmental Protection Agency on the National Priorities List. The following table presents Occidental's environmental remediation reserves, the current portion of which is included in accrued liabilities ($69 million in 2007, $79 million in 2006 and $83 million in 2005) and the remainder in deferred credits and other liabilities — other ($388 million in 2007, $333 million in 2006 and $335 million in 2005). The reserves are grouped by three categories of environmental remediation sites:

$ amounts in millions	2007			2006			2005
	Number of Sites	Reserve Balance		Number of Sites	Reserve Balance		Number of Sites	Reserve Balance
CERCLA & equivalent sites	105	$	225	105	$	226	128	$	236
Active facilities	17		99	21		116	18		114
Closed or sold facilities	41		133	40		70	39		68
Total	163	$	457	166	$	412	185	$	418

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

In millions	2007			2006			2005
Balance — Beginning of Year	$	412		$	418		$	375
Remediation expenses and interest accretion		108			48			63
Changes from acquisitions/dispositions		5			17			45
Payments		(68	)		(71	)		(71	)
Other		—			—			6
Balance — End of Year	$	457		$	412		$	418

CERCLA and Equivalent Sites

As of December 31, 2007, OPC or certain of its subsidiaries have been named in 105 CERCLA or equivalent proceedings, as shown below.

Description ($ amounts in millions)	Number of Sites	Reserve Balance
Minimal/No exposure ^(a)	85	$	7
Reserves between $1-10 MM	14		47
Reserves over $10 MM	6		171
Total	105	$	225

(a)

Active Facilities

Closed or Sold Facilities

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	2007		2006		2005
Operating Expenses
Oil and Gas	$	108	$	95	$	65
Chemical		80		73		67
	$	188	$	168	$	132
Capital Expenditures
Oil and Gas	$	59	$	55	$	43
Chemical		14		25		21
	$	73	$	80	$	64
Remediation Expenses
Corporate	$	107	$	47	$	62

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.

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 the current year 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.

At December 31, 2007, commitments for major capital expenditures during 2008 and thereafter were approximately $330 million.

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 $3.8 to $3.9 billion in capital expenditures estimated for 2008.

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 other affiliates will meet their various obligations (guarantees).

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, 2007, 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
2007	$	4,604	$	3,981	$	8,585
2006	$	4,281	$	3,275	$	7,556
2005	$	4,348	$	2,331	$	6,679

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
2007
Current	$	1,371		$	125		$	1,976		$	3,472
Deferred		48			14			(27	)		35
	$	1,419		$	139		$	1,949		$	3,507
2006
Current	$	1,370		$	114		$	1,772		$	3,256
Deferred		154			(13	)		(43	)		98
	$	1,524		$	101		$	1,729		$	3,354
2005
Current	$	537		$	121		$	1,237		$	1,895
Deferred		(57	)		(9	)		12			(54	)
	$	480		$	112		$	1,249		$	1,841

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 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 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,	2007		2006		2005
United States federal statutory tax rate	35	%	35	%	35	%
Operations outside the United States	6		8		6
State taxes, net of federal benefit	1		1		1
Reversal of tax reserves	—		—		(13	)
Other	(1	)	—		(1	)
Tax rate provided by Occidental	41	%	44	%	28	%

The tax effects of temporary differences resulting in deferred income taxes at December 31, 2007 and 2006 were as follows:

	2007					2006
	Deferred			Deferred		Deferred			Deferred
Tax effects of temporary differences (in millions)	Tax Assets			Tax Liabilities		Tax Assets			Tax Liabilities
Property, plant and equipment differences	$	180		$	3,541	$	189		$	3,168
Investments including partnerships		—			—		—			217
Environmental reserves		186			—		162			—
Postretirement benefit accruals		243			—		233			—
Deferred compensation and benefits		259			—		208			—
Asset retirement obligations		136			—		82			—
Derivatives		218			—		70			—
Foreign tax credit carryforward		242			—		133			—
State income taxes		71			—		106			—
All other		459			251		317			108
Subtotal		1,994			3,792		1,500			3,493
Valuation allowance		(296	)		—		(183	)		—
Total deferred taxes	$	1,698		$	3,792	$	1,317		$	3,493

Included in total deferred tax assets was a current portion aggregating $230 million and $190 million as of December 31, 2007 and 2006, respectively, that was reported in prepaid expenses and other.

Occidental has, as of December 31, 2007, foreign tax credit carryforwards of $242 million which expire in varying amounts through 2017 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 $4.8 billion at December 31, 2007, 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 $60 million would be required, assuming utilization of available foreign tax credits.

The discontinued operations include an income tax charge of $141 million in 2007, a benefit of $92 million in 2006, and a charge of $188 million in 2005.

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 $43 million in 2007, $140 million in 2006 and $74 million in 2005 for a tax benefit from the exercise of certain stock-based compensation awards.

As discussed in Note 3, Occidental adopted FIN No. 48 on January 1, 2007. The following table shows the effect of adopting FIN No. 48 on the consolidated balance sheet at January 1, 2007 (in millions):

	Debit/(Credit)
Domestic and foreign income taxes – Current	$	140
Deferred and other domestic and foreign income taxes	$	(8	)
Deferred credits and other liabilities – Other	$	100
Minority interest	$	(13	)
Retained earnings	$	(219	)

As of the January 1, 2007 adoption, Occidental had liabilities for unrecognized tax benefits of approximately $77 million included in deferred credits and other liabilities – other, which included approximately $61 million that, if subsequently recognized, would have affected Occidental’s effective tax rate. As of December 31, 2007, Occidental had liabilities for unrecognized tax benefits of approximately $83 million included in deferred credits and other liabilities – other, which included approximately $66 million that, if subsequently recognized, would have affected Occidental’s effective tax rate.

A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:

For the year ended December 31, (in millions)	2007
Balance at January 1, 2007	$	77
Additions based on tax positions related to the current year		13
Reductions based on tax positions related to prior years		(7	)
Balance at December 31, 2007	$	83

Occidental continues to recognize an estimate of potential interest and penalties related to liabilities for unrecognized tax benefits in the provisions for domestic and foreign income and other taxes. For the years ended December 31, 2007, 2006 and 2005, Occidental recognized approximately $2 million, $5 million and $2 million, respectively, in interest and penalties. Occidental’s accrued interest and penalties were $11 million and $15 million as of December 31, 2007 and 2006, respectively.

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 and state corporate income tax purposes. Taxable years 2001 through the current year are in various stages of audit by the U.S. Internal Revenue Service. Foreign government tax authorities are in various stages of auditing Occidental, and income taxes for taxable years from 2002 through 2007 remain subject to examination. Disputes may arise during the course of such audits as to facts and matters of law.

It is reasonably possible that Occidental’s existing liabilities for unrecognized tax benefits may increase or decrease within the next twelve months primarily due to the progression of audits in process or the expiration of statutes of limitation. Occidental cannot reasonably estimate a range of potential changes in such benefits due to the unresolved nature of the various audits.

NOTE 11 STOCKHOLDERS' EQUITY

The following is an analysis of common stock:

(shares in thousands)		Common Stock
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
Issued		2,933
Options exercised and other, net		3,512
Balance, December 31, 2007		877,124

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 2007, the Board of Directors authorized an increase to Occidental's treasury stock purchase program under which Occidental is authorized to purchase up to 55 million shares of its common stock. Additionally, Occidental purchased shares from the trustee of its defined contribution savings plan. In 2007, Occidental purchased 20.6 million shares under the programs at an average cost of $54.75 per share. In 2006, Occidental purchased 30.6 million shares under the programs at an average cost of $48.20 per share.

In February 2008, the Board of Directors authorized an increase to Occidental's treasury stock purchase program, which increased the number of shares that Occidental is authorized to purchase from 55 to 75 million shares.

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, 2007, 2006 and 2005, 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	2007			2006			2005
Basic Earnings per Share
Weighted average common shares outstanding		874.0			860.9			799.9
Weighted average treasury shares		(42.1	)		(15.9	)		—
Vested, unissued shares		3.0			7.6			6.7
Basic Shares		834.9			852.6			806.6
Diluted Earnings per Share
Basic shares		834.9			852.6			806.6
Dilutive effect of stock options and unvested restricted shares		4.2			7.8			11.6
Dilutive Shares		839.1			860.4			818.2

ACCUMULATED OTHER COMPREHENSIVE LOSS

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

Balance at December 31, (in millions)	2007			2006
Foreign currency translation adjustments	$	(10	)	$	(24	)
Derivative mark-to-market adjustments		(441	)		(259	)
Pension and post-retirement adjustments ^(a)		(181	)		(168	)
Unrealized gains on securities		—			118
Total	$	(632	)	$	(333	)

(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, TSRIs, CSSUs and dividend equivalents. These awards were granted under the 1995 Incentive Stock Plan (1995 ISP), 2001 Incentive Compensation Plan (2001 ICP), Phantom Share Unit Awards Plan 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, 2007. An aggregate of 66 million shares of Occidental common stock are reserved for issuance under the 2005 LTIP and at December 31, 2007, approximately 43.3 million shares of Occidental common stock were available for future awards. All non-employee director awards are now granted under the 2005 LTIP. During 2007, non-employee directors were granted awards for 59,800 shares of restricted stock that fully vested on the grant date. Awards that have been granted to directors under the 2005 LTIP are restricted and may not be sold or transferred for three years, except in the case of death or disability, 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)

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 past three years (all amounts in millions):

Year Ended December 31	2007		2006		2005
Compensation expense	$	290	$	211	$	186
Income tax benefit recognized in the income statement	$	105	$	77	$	68
Intrinsic value of options and stock-settled SAR exercises	$	110	$	494	$	227
Liabilities paid ^(a)	$	95	$	34	$	11
Fair value of RSUs and PSAs vested during the year ^(b)	$	128	$	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, 2007, there was $209 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 1.9 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
Assumptions used:
Risk-free interest rate	5.0%	3.7%	3.4%
Dividend yield	1.4%	1.5%	2.2%
Volatility factor	26%	27%	21%
Expected life (years)	5.5	5.5	3.6

The grant date fair values of each stock-settled SAR granted in 2006 and 2005 were $14.77 and $10.76, respectively. The grant date fair value of each Option granted in 2004 was $4.02. 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 2007:

2007

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, 2007

12,852

32.45

5,210

24.66

Exercised

(2,912

)

20.93

(2,047

)

24.66

Forfeited or expired

—

(37

)

24.66

Ending balance,

December 31, 2007

9,940

35.83

7.1

409,135

3,126

24.66

6.5

163,571

Exercisable at

December 31, 2007

6,555

30.19

6.6

306,723

3,126

24.66

6.5

163,571

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 2007, 2006, 2005, 2004 and 2003 were $52.68, $50.45, $40.91, $25.35 and $16.55, respectively.

A summary of changes in Occidental’s unvested RSUs during the year ended December 31, 2007 is presented below:

	2007
	RSUs (000’s)		Weighted Average Grant Date Fair Value
Unvested at January 1	3,082		$	39.79
Granted	22		$	52.68
Vested	(1,553	)	$	36.96
Forfeitures	(31	)	$	46.42
Unvested at December 31	1,520		$	42.73

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 0 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, 2007, is presented below:

	2007
	PRSUs (000’s)	Weighted Average Grant Date Fair Value
Unvested at January 1	758	$	50.45
Granted or issued	—	$	—
Unvested at December 31	758	$	50.45

PSAs and TSRIs

Certain executives are awarded PSAs and TSRIs that vest at the end of the four-year period following the grant date if performance targets are certified as being met. For PSAs granted prior to July 2007 payouts range from 0 to 200 percent of the target award and include 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 substantially in cash. For TSRIs granted in July 2007, payouts range from 0 to 150 percent of the target award and include provisions to provide for settlement, once certified, to occur equally in stock and cash. Dividend equivalents for PSA and TSRI target shares are paid during the performance period regardless of the payout range or settlement provision.

The fair values of the stock-settled portion of PSAs and TSRIs are measured on the grant date using a Monte Carlo simulation model using Occidental's assumptions, noted in the following table, and the volatility from corresponding peer companies. 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 grant-date assumptions used in the Monte Carlo simulation model for stock-settled PSAs and TSRIs were as follows:

	TSRIs	PSAs
Year Granted	July 2007	2007	2006	2005	2004
Assumptions used:
Risk-free interest rate	4.4%	4.1%	4.0%	3.3%	3.0%
Dividend yield	1.7%	1.9%	1.7%	1.9%	2.5%
Volatility factor	26%	25%	32%	21%	29%
Expected life (years)	4	4	4	4	4
Grant date fair value of underlying Occidental common stock	$61.93	$48.83	$39.94	$29.18	$21.12

The fair value of the cash-settled portion of PSAs and TSRIs 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 and TSRIs are recorded as compensation expense.

A summary of Occidental’s unvested PSAs and TSRIs as of December 31, 2007 and changes during the year ended December 31, 2007, is presented below:

2007

PSAs

(000’s)

Grant Date Fair Value

of Occidental Stock

TSRIs

(000’s)

Grant Date Fair Value

of Occidental Stock

Unvested at January 1 ^(a)

1,402

19.69

—

Granted ^{(a, b)}

168

48.83

523

61.93

Vested ^(c)

(563

)

14.23

—

Forfeitures

(34

)

47.95

—

Unvested at December 31 ^(a)

973

47.01

523

61.93

(a)	Unvested awards and award grants are presented at the target payouts.
(b)	Actual payout may be up to 200 percent of this amount for PSAs granted prior to July 2007. The TSRIs granted in July 2007 have a maximum payout of 150 percent.
(c)	The weighted-average payout at vesting was 198 percent of the target.

CSSUs

Certain employees are awarded the right to receive CSSUs (which include and have been issued as Long-Term Incentive awards). CSSUs are equivalent in value to actual shares of Occidental common stock but are paid in cash at the time of vesting. The fair value of the CSSUs is measured on the grant date using the quoted market price of Occidental common stock and expensed on a straight-line basis over the vesting period. CSSUs vest either in total over two years or ratably over three years after the grant date and can be forfeited or accelerated under certain conditions. For CSSUs which vest in total over two years, dividend equivalents are accumulated during the vesting period and are paid when they vest. For CSSUs which vest ratably, dividend equivalents are paid during the vesting period. Changes in the fair value between the grant date and the date when the CSSUs vest are recognized as compensation expense. The weighted average grant date fair values of the CSSUs granted in 2007 and 2006 were $61.90 and $48.59, respectively.

A summary of changes in Occidental’s unvested CSSUs during the year ended December 31, 2007 is presented below:

	2007
	CSSUs (000’s)		Weighted Average Grant Date Fair Value
Unvested at January 1	675		$	48.59
Granted	661		$	61.90
Vested	—		$	—
Forfeitures	(80	)	$	59.44
Unvested at December 31	1,256		$	55.39

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
Net Income	$	5,293
Add: Stock-based compensation included in net income, net of tax, under
APB Opinion No. 25 ^(a)		104
Deduct: Stock-based compensation, net of tax, determined under
SFAS No. 123(R) fair value method ^(a)		(112	)
Pro forma net income	$	5,285
Earnings per share:
Basic — as reported	$	6.56
Basic — pro forma	$	6.55
Diluted — as reported	$	6.47
Diluted — pro forma	$	6.46

(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. As discussed in Note 3, on December 31, 2006, Occidental adopted the provisions of SFAS No. 158.

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 $84 million, $70 million and $61 million as of December 31, 2007, 2006 and 2005, respectively, and Occidental expensed $86 million in 2007, $74 million in 2006 and $66 million in 2005 under the provisions of these defined contribution and supplemental retirement plans.

DEFINED BENEFIT PLANS

Participation in the defined benefit plans is limited and approximately 1,000 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 total benefit costs, including the postretirement costs, were approximately $131 million in 2007, $120 million in 2006 and $104 million in 2005.

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)	2007			2006			2007			2006			2007			2006
Changes in benefit obligation:
Benefit obligation — beginning of year	$	523		$	492		$	619		$	614		$	29		$	26
Service cost — benefits earned during the period		9			11			12			10			1			—
Interest cost on projected benefit obligation		27			27			34			33			2			2
Actuarial (gain) loss		(6	)		(6	)		47			16			2			1
Foreign currency exchange rate changes		12			2			—			—			—			—
Acquisitions ^(a)		—			28			—			—			—			1
Benefits paid		(41	)		(30	)		(50	)		(54	)		(1	)		(1	)
Plan amendments		3			(1	)		—			—			—			—
Benefit obligation — end of year	$	527		$	523		$	662		$	619		$	33		$	29
Changes in plan assets:
Fair value of plan assets — beginning of year	$	556		$	424		$	—		$	—		$	3		$	2
Actual return on plan assets		39			68			—			—			1			—
Foreign currency exchange rate changes		2			1			—			—			—			—
Employer contribution		11			66			—			—			1			1
Benefits paid		(41	)		(30	)		—			—			(1	)		(1	)
Acquisitions ^(a)		—			27			—			—			—			1
Fair value of plan assets — end of year	$	567		$	556		$	—		$	—		$	4		$	3
Funded (unfunded) status:	$	40		$	33		$	(662	)	$	(619	)	$	(29	)	$	(26	)

(a)	Relates to the acquisition of Tidelands in 2006.

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 $111 million, $104 million and zero, respectively, as of December 31, 2007, and $96 million, $90 million and zero, respectively, as of December 31, 2006. 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 $415 million, $396 million and $566 million, respectively, as of December 31, 2007, and $427 million, $404 million, and $556 million, respectively, as of December 31, 2006.

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)	2007			2006			2007			2006			2007			2006
Other assets	$	156		$	135		$	—		$	—		$	—		$	—
Accrued liabilities		(3	)		(3	)		(49	)		(53	)		—			—
Deferred credits and other liabilities – other		(113	)		(99	)		(613	)		(566	)		(29	)		(26	)
	$	40		$	33		$	(662	)	$	(619	)	$	(29	)	$	(26	)

At December 31, 2007 and 2006, AOCI included the following after-tax balances:

	Pension Benefits				Postretirement Benefits
					Unfunded Plans				Funded Plans
As of December 31, (in millions)	2007		2006		2007		2006		2007		2006
Net loss	$	19	$	28	$	149	$	128	$	8	$	7
Prior service cost		2		1		3		4		—		—
	$	21	$	29	$	152	$	132	$	8	$	7

Occidental does not expect any plan assets to be returned during 2008.

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)	2007			2006			2005			2007		2006		2005		2007			2006		2005
Net periodic benefit costs:
Service cost — benefits earned during the period	$	9		$	11		$	12		$	12	$	10	$	9	$	1		$	—	$	—
Interest cost on benefit obligation		27			27			25			34		33		32		2			2		1
Expected return on plan assets		(38	)		(33	)		(32	)		—		—		—		(1	)		—		—
Amortization of prior service cost		1			1			1			1		1		1		—			—		—
Recognized actuarial loss		3			1			—			14		16		14		1			1		1
Settlement and special termination benefits
cost ^(a)		3			—			4			—		—		3		—			—		—
Currency adjustments		10			2			4			—		—		—		—			—		—
Net periodic benefit cost	$	15		$	9		$	14		$	61	$	60	$	59	$	3		$	3	$	2

(a)	Settlement cost relates to benefit distributions made in 2007 and special termination benefits cost relates to the Pottstown plant closure in 2005.

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 zero and $1 million, respectively. 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 $16 million and $1 million, respectively.

ADDITIONAL INFORMATION

Occidental’s defined benefit pension and postretirement 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,	2007	2006	2007	2006	2007	2006
Benefit Obligation Assumptions:
Discount rate	5.68%	5.53%	5.68%	5.53%	5.68%	5.53%
Rate of compensation increase	4.00%	4.00%	—	—	—	—
Net Periodic Benefit Cost Assumptions:
Discount rate	5.53%	5.33%	5.53%	5.33%	5.53%	5.33%
Assumed long term rate of return on assets	7.00%	7.50%	—	—	7.00%	7.50%
Rate of compensation increase	4.00%	4.00%	—	—	—	—

For domestic pension plans and postretirement benefit plans, Occidental bases the discount rate on the Hewitt Bond Universe yield curve in 2007 and the average yield provided by the Moody’s Aaa Corporate Bond Index in 2006. 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, Occidental bases its discount rate on rates indicative of government and/or investment grade corporate debt in the applicable country, taking into account hyperinflationary environments where necessary. The discount rates used for the foreign pension plans ranged from 3 to 11 percent at both December 31, 2007 and 2006. The average rate of increase in future compensation levels ranged from a low of 2 percent to a high of 10 percent in 2007, 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 2007 and 2006.

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 an assumed Consumer Price Index (CPI) increase of 2.5 percent as of December 31, 2007 and 2006 (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 10 percent in 2007 to 6 percent through the year 2011 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 $21 million or a reduction of $20 million, respectively, in the postretirement benefit obligation as of December 31, 2007, and a corresponding increase or reduction of $1 million in interest cost in 2007. 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,	2007		2006		2007		2006
Asset Category:
Equity securities	57	%	56	%	54	%	55	%
Debt securities	43		44		46		45
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 2008. 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
2008	$	32	$	51
2009	$	34	$	51
2010	$	36	$	50
2011	$	38	$	50
2012	$	38	$	49
2013 — 2017	$	216	$	239

NOTE 14 INVESTMENTS AND RELATED-PARTY TRANSACTIONS

At December 31, 2007 and 2006, investments in unconsolidated entities comprised $521 million and $498 million of equity method investments and $234 million and $294 million of advances to equity method investees, respectively. The remainder of the 2007 investments in unconsolidated entities reflects available-for-sale securities.

EQUITY INVESTMENTS

At December 31, 2007, 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 $33 million, $113 million and $161 million to Occidental in 2007, 2006 and 2005, respectively. At December 31, 2007, cumulative undistributed earnings of equity-method investees since acquisition were $120 million. At December 31, 2007, Occidental’s investments in equity investees exceeded the underlying equity in net assets by $252 million, of which $140 million represents goodwill that will not be amortized and $112 million represents intangible assets, which is being amortized over the life of the underlying assets.

The following table presents Occidental’s ownership interest in the summarized financial information of its equity method investments:

For the years ended December 31, (in millions)	2007		2006		2005
Revenues	$	463	$	1,569	$	3,637
Costs and expenses		381		1,386		3,405
Net income	$	82	$	183	$	232
As of December 31,	2007		2006
Current assets	$	130	$	151
Non-current assets	$	853	$	812
Current liabilities	$	88	$	101
Long-term debt	$	603	$	562
Other non-current liabilities	$	30	$	26
Stockholders’ equity	$	262	$	274

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 through April 2008 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 facility to fund the construction of a certain portion of the Dolphin Project. Occidental guarantees 24.5 percent of both of these obligations of Dolphin Energy. At December 31, 2007, Occidental’s portion of the bridge loan and financing facility was $816 million. Occidental had recorded $588 million on the balance sheet at December 31, 2007, for the combined bridge loan and financing facility. The remaining amounts of the bridge loan and financing facility drawdowns are included in the guarantee amounts discussed in Note 9.

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, which has not been exercised to date. At December 31, 2007, the total pre-tax advance tariff payment of approximately $89 million was accrued in Occidental’s consolidated financial statements. This advance tariff would be used by the pipeline company to service or prepay project debt. At December 31, 2007, 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 2.5 percent and is due December 31, 2008. At December 31, 2007 and 2006, the outstanding balance on the Note was $182 million and $196 million, respectively. 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, 2007 and 2006, the outstanding balance on the Revolver and related accrued interest were $51 million and $1 million and $55 million and $1 million, respectively.

AVAILABLE-FOR-SALE SECURITIES

Lyondell

Starting in 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 believed that it no longer had the ability to exercise significant influence over Lyondell’s financial and operating policies and 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 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 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.

In 2007, Occidental sold all of its remaining shares of Lyondell common stock (approximately 21 million shares) for a pre-tax gain of $326 million and gross proceeds of $672 million.

Premcor

Valero's acquisition of Premcor and the subsequent sale by Occidental of all of the Valero shares received resulted in a pre-tax gain of $726 million 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 2007, 2006 and 2005, Occidental entered into the following related-party transactions and had the following amounts due from or to its related parties:

December 31, (in millions)	2007		2006		2005
Purchases ^(a)	$	236	$	688	$	1,275
Sales	$	351	$	589	$	980
Services	$	1	$	6	$	6
Advances and amounts due from	$	184	$	216	$	256
Amounts due to	$	—	$	1	$	16

(a)	In 2007, purchases from Elk Hills Power, LLC accounted for 98 percent. In 2006 and 2005, purchases from Lyondell accounted for 38 and 59 percent, respectively.

NOTE 15 INDUSTRY SEGMENTS AND GEOGRAPHIC AREAS

Occidental conducts its continuing operations through two reportable segments: 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 available-for-sale investment in Lyondell (sold in 2007), 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 two common carrier oil pipeline systems in the Permian Basin.

INDUSTRY SEGMENTS

In millions

	Oil and Gas			Chemical			Corporate and Other			Total
YEAR ENDED DECEMBER 31, 2007
Net sales	$	13,918	^(a)	$	4,664	^(b)	$	202		$	18,784
Pretax operating profit (loss)	$	8,318		$	601		$	(334	) ^(c)	$	8,585
Income taxes		—			—			(3,507	)		(3,507	)
Discontinued operations, net		—			—			322			322
Net income (loss)	$	8,318	^(d)	$	601		$	(3,519	) ^(e)	$	5,400
Investments in unconsolidated entities	$	474		$	118		$	191		$	783
Property, plant and equipment additions, net ^(f)	$	3,206		$	251		$	40		$	3,497
Depreciation, depletion and amortization	$	2,024		$	304		$	51		$	2,379
Total assets	$	29,465		$	3,814		$	3,240		$	36,519
YEAR ENDED DECEMBER 31, 2006
Net sales	$	12,190	^(a)	$	4,815	^(b)	$	170		$	17,175
Pretax operating profit (loss)	$	6,880		$	906		$	(230	) ^(c)	$	7,556
Income taxes		—			—			(3,354	) ^(e)		(3,354	)
Discontinued operations, net		—			—			(11	)		(11	)
Net income (loss)	$	6,880		$	906		$	(3,595	) ^(e)	$	4,191
Investments in unconsolidated entities	$	515		$	103		$	726		$	1,344
Property, plant and equipment additions, net ^(f)	$	2,703		$	251		$	33		$	2,987
Depreciation, depletion and amortization	$	1,702		$	279		$	27		$	2,008
Total assets	$	25,418		$	3,801		$	3,212		$	32,431
YEAR ENDED DECEMBER 31, 2005
Net sales	$	9,361	^(a)	$	4,641	^(b)	$	151		$	14,153
Pretax operating profit	$	5,662		$	614		$	403	^(c)	$	6,679
Income taxes		—			—			(1,841	) ^(e)		(1,841	)
Discontinued operations, net		—			—			452			452
Cumulative effect of changes in accounting principles, net		—			—			3			3
Net income (loss)	$	5,662	^(d)	$	614	^(g)	$	(983	) ^(e)	$	5,293
Investments in unconsolidated entities	$	436		$	92		$	688		$	1,216
Property, plant and equipment additions, net ^(f)	$	2,108		$	173		$	14		$	2,295
Depreciation, depletion and amortization	$	1,083		$	268		$	21		$	1,372
Total assets	$	18,394		$	3,872		$	3,904		$	26,170

(See footnotes on next page)

Footnotes:

(a)	Oil sales represented approximately 81 percent, 80 percent and 77 percent of the oil and gas segment net sales for the years ended December 31, 2007, 2006 and 2005, respectively.
(b)	Total product sales for the chemical segment were as follows:

	Basic Chemicals	Vinyls	Performance Chemicals
Year ended December 31, 2007	52%	45%	3%
Year ended December 31, 2006	48%	48%	4%
Year ended December 31, 2005	46%	50%	4%

(c)	Includes unallocated net interest expense, administration expense, environmental remediation and other pre-tax items noted in footnote (e) below.
(d)	The 2007 amount includes an after-tax gain of $412 million from the sale of Occidental’s interest in a Russian joint venture, an after-tax gain of $112 million from certain litigation settlements, a pre-tax gain of $103 million from the sale of exploration properties, a pre-tax gain of $35 million from the sale of miscellaneous domestic oil and gas interests and a $74 million pre-tax loss from the impairment of properties. The 2005 amount includes a contract settlement charge of $26 million and a hurricane insurance charge of $18 million.
(e)	Includes the following significant items affecting earnings for the years ended December 31:

Benefit (Charge) (In millions)	2007			2006			2005
CORPORATE
Pre-tax operating profit (loss)
Gain on sale of Lyondell shares	$	326		$	90		$	140
Debt purchase expense		(167	)		(31	)		(42	)
Facility closure		(47	)		—			—
Severance charge		(25	)		—			—
Litigation settlements		—			108			—
Gain on Premcor-Valero shares		—			—			726
Equity investment impairment		—			—			(15	)
Equity investment hurricane insurance charge		—			—			(2	)
Hurricane insurance charge		—			—			(10	)
	$	87		$	167		$	797
Income taxes
State tax issue charge *	$	—		$	—		$	(10	)
Settlement of federal tax issues *		—			—			619
Deferred tax write-off due to compensation program changes *		—			(40	)		—
Reversal of tax reserves *		—			—			335
Tax effect of pre-tax adjustments		(2	)		(41	)		(219	)
	$	(2	)	$	(81	)	$	725
Discontinued operations, net *	$	322		$	(11	)	$	452
Changes in accounting principles, net *	$	—		$	—		$	3

*	Amounts shown after-tax.

(f)	Excludes acquisitions. Amounts include capitalized interest of $57 million in 2007, $51 million in 2006 and $26 million in 2005.
(g)	Chemical includes the 2005 write-off of plants of $159 million and a hurricane insurance charge of $11 million.

GEOGRAPHIC AREAS

In millions

	Net sales ^(a)						Property, plant and equipment, net
For the years ended December 31,	2007		2006		2005		2007		2006		2005
United States	$	12,300	$	11,569	$	10,291	$	17,838	$	16,552	$	13,435
Foreign
Qatar		2,014		1,639		1,299		2,025		1,727		1,671
Colombia		1,271		995		829		402		304		214
Yemen		861		877		678		494		495		276
Oman		741		633		489		1,215		815		489
Libya		625		549		183		222		244		223
Argentina		461		527		—		3,031		2,993		—
Canada		208		249		276		35		29		29
United Arab Emirates		131		—		—		939		825		568
Other Foreign		172		137		108		77		154		59
Total Foreign		6,484		5,606		3,862		8,440		7,586		3,529
Total	$	18,784	$	17,175	$	14,153	$	26,278	$	24,138	$	16,964

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

NOTE 16 COSTS AND RESULTS OF OIL AND GAS PRODUCING ACTIVITIES

In 2007, Occidental completed an exchange of oil and gas interests in Horn Mountain with BP for oil and gas interests in the Permian Basin and a gas processing plant in Texas. Occidental also sold its oil and gas interests in Pakistan to BP in 2007. In 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 has classified its Horn Mountain, Pakistan and Ecuador operations as discontinued operations on a retrospective basis and excluded them from all tables in Note 16.

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, 2007
Proved properties	$	19,026		$	3,965		$	7,763		$	—		$	30,754		$	(129	)
Unproved properties ^(a)		810			527			228			—			1,565			—
Total property costs		19,836			4,492			7,991			—			32,319			(129	)
Support facilities		1,171			239			188			—			1,598			6
Total capitalized costs ^(b)		21,007			4,731			8,179			—			33,917			(123	)
Accumulated depreciation,
depletion and amortization ^(d)		(6,351	)		(1,241	)		(3,284	)		—			(10,876	)		132
Net capitalized costs	$	14,656		$	3,490		$	4,895		$	—		$	23,041		$	9
DECEMBER 31, 2006
Proved properties	$	16,838		$	3,493		$	6,395		$	—		$	26,726		$	76
Unproved properties ^(a)		802			655			265			37			1,759			1
Total property costs		17,640			4,148			6,660			37			28,485			77
Support facilities		890			95			148			—			1,133			19
Total capitalized costs ^(b)		18,530			4,243			6,808			37			29,618			96
Accumulated depreciation,
depletion and amortization ^(d)		(5,060	)		(888	)		(2,701	)		—			(8,649	)		(36	)
Net capitalized costs	$	13,470		$	3,355		$	4,107		$	37		$	20,969		$	60
DECEMBER 31, 2005
Proved properties	$	13,514		$	791		$	4,923		$	—		$	19,228		$	47
Unproved properties ^(a)		475			—			385			36			896			—
Total property costs		13,989			791			5,308			36			20,124			47
Support facilities		700			36			109			2			847			17
Total capitalized costs ^(b)		14,689			827			5,417			38			20,971			64
Accumulated depreciation,
depletion and amortization ^(d)		(4,159	)		(613	)		(2,189	)		(2	)		(6,963	)		(26	)
Net capitalized costs	$	10,530		$	214		$	3,228		$	36		$	14,008		$	38

(a)	The 2007 amount primarily consists of California, Argentina and Libya. 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.
(b)	Includes costs related to leases, exploration costs, lease and well equipment, pipelines and terminals, gas plant, other equipment and capitalized interest.
(c)	The 2007 amounts reflect the minority interest in a Colombian subsidiary, partially offset by Occidental's share of capitalized costs from an equity investee in Yemen. The 2006 and 2005 amounts include Occidental’s share of capitalized costs from an equity investee in Yemen and a Russian joint venture, partially offset by the minority interest in a Colombian subsidiary. Occidental's joint venture interest in Russia was sold in 2007.
(d)	Includes allowance for unproved properties impairments of $137 million in 2007, $108 million in 2006 and $108 million in 2005.

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, 2007
Property Acquisition Costs
Proved Properties	$	716	$	—		$	300	$	—	$	1,016	$	—
Unproved Properties		167		(58	)		10		—		119		—
Exploration costs		39		79			193		20		331		(4	)
Development costs		1,431		524			1,032		—		2,987		7
Costs Incurred	$	2,353	$	545		$	1,535	$	20	$	4,453	$	3
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		39		61			177		36		313		1
Development costs		1,406		320			792		—		2,518		32
Costs Incurred	$	3,916	$	3,444		$	1,473	$	39	$	8,872	$	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		27		56			47		102		232		(2	)
Development costs		1,000		56			834		—		1,890		15
Costs Incurred	$	2,822	$	112		$	1,262	$	106	$	4,302	$	13

(a)

The 2007 amounts reflect the minority interest in a Colombian subsidiary, partially offset by Occidental's share of costs incurred from an equity investee in Yemen. The 2006 and 2005 amounts include Occidental’s share of costs incurred from an equity investee in Yemen and a Russian joint venture, partially offset by the minority interest in a Colombian subsidiary. Occidental's joint venture interest in Russia was sold in 2007.

(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.

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, 2007
Revenues ^(b)	$	7,492	$	1,559	$	4,340	^(d)	$	—		$	13,391	$	(68	)^(d)
Production costs		1,940		320		430			—			2,690		(5	)
Exploration expenses		112		56		224			30			422		(5	)
Other operating expenses		328		105		181			1			615		(3	)
Depreciation, depletion and
amortization		1,071		356		597			—			2,024		(6	)
Pretax income		4,041		722		2,908			(31	)		7,640		(49	)
Income tax expense^(c)		1,220		241		1,717	^(d)		—			3,178		(6	)^(d)
Results of operations	$	2,821	$	481	$	1,191		$	(31	)	$	4,462	$	(43	)
FOR THE YEAR ENDED
DECEMBER 31, 2006
Revenues ^(b)	$	6,778	$	1,358	$	3,659	^(d)	$	—		$	11,795	$	223	^(d)
Production costs		1,707		280		351			—			2,338		149
Exploration expenses		89		32		140			35			296		1
Other operating expenses		409		47		121			3			580		8
Depreciation, depletion and
amortization		902		275		525			—			1,702		10
Pretax income		3,671		724		2,522			(38	)		6,879		55
Income tax expense^(c)		1,060		310		1,424	^(d)		2			2,796		11	^(d)
Results of operations	$	2,611	$	414	$	1,098		$	(40	)	$	4,083	$	44
FOR THE YEAR ENDED
DECEMBER 31, 2005
Revenues ^(b)	$	5,739	$	666	$	2,633	^(d)	$	—		$	9,038	$	286	^(d)
Production costs		1,298		74		207			—			1,579		203
Exploration expenses		128		53		56			72			309		(2	)
Other operating expenses		290		6		112			—			408		7
Depreciation, depletion and
amortization		680		55		347			—			1,082		11
Pretax income		3,343		478		1,911			(72	)		5,660		67
Income tax expense^(c)		906		224		1,028	^(d)		4			2,162		3	^(d)
Results of operations	$	2,437	$	254	$	883		$	(76	)	$	3,498	$	64

(a)	The 2007 amounts reflect the minority interest in a Colombian subsidiary, partially offset by Occidental's share of the results of operations from an equity investee in Yemen. The 2006 and 2005 amounts include Occidental’s share of the results of operations from an equity investee in Yemen and a Russian joint venture, partially offset by the minority interest in a Colombian subsidiary. Occidental's joint venture interest in Russia was sold in 2007.
(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, 2007
Revenues from net production
Barrel of oil equivalent ($/bbl.)^(c,d)	$	57.19	$	52.33	$	62.49	^(b)	$	—	$	57.72	$	68.74	^(b)
Production costs		14.81		10.74		8.91			—		12.87		14.44
Exploration expenses		0.85		1.88		4.64			—		2.02		—
Other operating expenses		2.51		3.52		3.75			—		2.94		0.51
Depreciation, depletion and
amortization		8.18		11.95		12.37			—		9.68		12.55
Pretax income		30.84		24.24		32.82			—		30.21		41.24
Income tax expense ^(e)		9.31		8.09		8.13	^(b)		—		8.86		10.29	^(b)
Results of operations	$	21.53	$	16.15	$	24.69		$	—	$	21.35	$	30.95
FOR THE YEAR ENDED
DECEMBER 31, 2006
Revenues from net production
Barrel of oil equivalent ($/bbl.)^(c,d)	$	52.48	$	48.63	$	59.40	^(b)	$	—	$	53.42	$	29.75	^(b)
Production costs		13.22		10.02		8.22			—		11.70		15.40
Exploration expenses		0.69		1.15		3.27			—		1.48		0.19
Other operating expenses		3.17		1.69		2.84			—		2.90		0.86
Depreciation, depletion and
amortization		6.98		9.84		12.30			—		8.52		2.30
Pretax income		28.42		25.93		32.77			—		28.82		11.00
Income tax expense ^(e)		8.21		11.11		7.06	^(b)		—		8.38		2.49	^(b)
Results of operations	$	20.21	$	14.82	$	25.71		$	—	$	20.44	$	8.51
FOR THE YEAR ENDED
DECEMBER 31, 2005
Revenues from net production
Barrel of oil equivalent ($/bbl.)^(c,d)	$	47.69	$	51.20	$	46.77	^(b)	$	—	$	47.76	$	33.28	^(b)
Production costs		10.79		5.69		5.54			—		9.25		19.76
Exploration expenses		1.06		4.07		1.50			—		1.81		—
Other operating expenses		2.41		0.46		3.00			—		2.39		0.75
Depreciation, depletion and
amortization		5.65		4.23		9.30			—		6.34		1.77
Pretax income		27.78		36.75		27.43			—		27.97		11.00
Income tax expense ^(e)		7.53		17.21		3.78	^(b)		—		7.47		1.86	^(b)
Results of operations	$	20.25	$	19.54	$	23.65		$	—	$	20.50	$	9.14

(a)	The 2007 amounts reflect the minority interest in a Colombian subsidiary, partially offset by Occidental's share of the results of operations from an equity investee in Yemen. The 2006 and 2005 amounts include Occidental’s share of the results of operations from an equity investee in Yemen and a Russian joint venture, partially offset by the minority interest in a Colombian subsidiary. Occidental's joint venture interest in Russia was sold in 2007.
(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 barrels of oil equivalent (BOE) 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.

2007 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

2,916

3,145

3,536

4,321

Chemical

1,060

1,229

1,241

1,134

Other

Net sales

4,015

4,411

4,841

5,517

Gross profit

1,964

2,206

2,544

3,105

Segment earnings

Oil and gas

2,008

1,682

2,029

2,599

Chemical

137

158

212

2,145

1,840

2,241

2,693

Unallocated corporate items

Interest expense, net

(181

)

(11

)

(13

)

Income taxes

(684

)

(904

)

(862

)

(1,057

)

Other

(111

)

203

(52

)

(175

)

Income from continuing operations

1,169

1,145

1,316

1,448

Discontinued operations, net

267

Net income

1,212

1,412

1,324

1,452

Basic earnings per common share

Income from continuing operations

1.39

1.36

1.58

1.75

Discontinued operations, net

0.05

0.32

0.01

—

Basic earnings per common share

1.44

1.68

1.59

1.75

Diluted earnings per common share

Income from continuing operations

1.38

1.36

1.57

1.74

Discontinued operations, net

0.05

0.32

0.01

—

Diluted earnings per common share

1.43

1.68

1.58

1.74

Dividends per common share

0.22

0.25

Market price per common share

High

50.46

59.73

65.86

79.25

Low

42.06

49.07

50.66

63.29

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	$	2,994		$	3,163		$	3,087		$	2,946
Chemical		1,241			1,273			1,265			1,036
Other		30			34			50			56
Net sales	$	4,265		$	4,470		$	4,402		$	4,038
Gross profit	$	2,357		$	2,368		$	2,336		$	1,944
Segment earnings
Oil and gas	$	1,811		$	1,857		$	1,790		$	1,422
Chemical		250			251			248			157
		2,061			2,108			2,038			1,579
Unallocated corporate items
Interest expense, net		(29	)		(33	)		(18	)		(51	)
Income taxes		(874	)		(851	)		(858	)		(771	)
Other		(71	)		(82	)		(59	)		113
Income from continuing operations		1,087			1,142			1,103			870
Discontinued operations, net		144			(282	)		67			60
Net income	$	1,231		$	860		$	1,170		$	930
Basic earnings per common share
Income from continuing operations	$	1.28		$	1.33		$	1.29		$	1.03
Discontinued operations, net		0.17			(0.33	)		0.08			0.07
Basic earnings per common share	$	1.45		$	1.00		$	1.37		$	1.10
Diluted earnings per common share
Income from continuing operations	$	1.26		$	1.31		$	1.28		$	1.02
Discontinued operations, net		0.17			(0.32	)		0.08			0.07
Diluted earnings per common share	$	1.43		$	0.99		$	1.36		$	1.09
Dividends per common share	$	0.18		$	0.18		$	0.22		$	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

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, NGLs, 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 reserves 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 2003.

Estimates of proven reserves are collected in a database and changes in this database are reviewed by engineering personnel to ensure accuracy. Finally, reserves volumes and changes are reviewed and approved by Occidental's senior management.

Oil Reserves

In millions of barrels

	Consolidated Subsidiaries
	United States		Latin America		Middle East/ North Africa		Total		Other Interests	^(b)
PROVED DEVELOPED AND UNDEVELOPED RESERVES
Balance at December 31, 2004	1,469		67		322	^(a)	1,858		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	(87	)	(13	)	(35	)	(135	)	(7	)
Balance at December 31, 2005	1,616		50		296	^(a)	1,962		45
Revisions of previous estimates	(28	)	10		39		21		(7	)
Improved recovery	69		33		14		116		(1	)
Extensions and discoveries	3		7		14		24		—
Purchases of proved reserves	98		152		4		254		—
Sales of proved reserves	(4	)	—		—		(4	)	—
Production	(94	)	(26	)	(40	)	(160	)	(7	)
Balance at December 31, 2006	1,660		226		327	^(a)	2,213		30
Revisions of previous estimates	(20	)	(17	)	(43	)	(80	)	—
Improved recovery	114		17		52		183		1
Extensions and discoveries	1		15		2		18		(1	)
Purchases of proved reserves	47		—		10		57		—
Sales of proved reserves	—		—		—		—		(33	)
Production	(95	)	(27	)	(43	)	(165	)	1
Balance at December 31, 2007	1,707		214		305	^(a)	2,226		(2	)
PROVED DEVELOPED RESERVES ^(c)
December 31, 2004	1,238		65		208		1,511		37
December 31, 2005	1,319		44		174		1,537		37
December 31, 2006	1,382		140		249		1,771		23
December 31, 2007	1,406		120		262		1,788		(2	)

(a)	All Middle East/North Africa amounts, except Libya, are related to PSCs, and do not include amounts related to taxes owed by Occidental but paid by governmental entities on its behalf.
(b)	The 2007 amounts reflect the minority interest in a Colombian subsidiary, partially offset by Occidental's share of reserves from an equity investee in Yemen. The 2006 and 2005 amounts include Occidental’s share of reserves from an equity investee in Yemen and a Russian joint venture, partially offset by the minority interest in a Colombian subsidiary. Occidental's joint venture interest in Russia was sold in 2007.
(c)	Approximately three percent of the proved developed reserves at December 31, 2007 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 2008.

Gas Reserves

In billions of cubic feet

	Consolidated Subsidiaries
	United States		Latin America		Middle East/ North Africa		Total		Other Interests
PROVED DEVELOPED AND UNDEVELOPED RESERVES
Balance at December 31, 2004	2,083		—		768	^(a)	2,851		—
Revisions of previous estimates	53		—		(32	)	21		6
Improved recovery	129		—		—		129		—
Extensions and discoveries	96		—		331		427		—
Purchases of proved reserves	164		—		—		164		—
Sales of proved reserves	(3	)	—		—		(3	)	—
Production	(199	)	—		(16	)	(215	)	(6	)
Balance at December 31, 2005	2,323		—		1,051	^(a)	3,374		—
Revisions of previous estimates	(135	)	45		59		(31	)	8
Improved recovery	120		—		7		127		—
Extensions and discoveries	58		—		—		58		—
Purchases of proved reserves	274		161		—		435		—
Sales of proved reserves	(2	)	—		—		(2	)	—
Production	(214	)	(12	)	(11	)	(237	)	(8	)
Balance at December 31, 2006	2,424		194		1,106	^(a)	3,724		—
Revisions of previous estimates	35		5		(130	)	(90	)	—
Improved recovery	406		5		6		417		—
Extensions and discoveries	5		19		11		35		—
Purchases of proved reserves	18		—		—		18		—
Sales of proved reserves	—		—		—		—		—
Production	(216	)	(15	)	(30	)	(261	)	—
Balance at December 31, 2007	2,672		208		963	^(a)	3,843		—
PROVED DEVELOPED RESERVES ^(b)
December 31, 2004	1,628		—		100		1,728		—
December 31, 2005	1,833		—		73		1,906		—
December 31, 2006	1,940		137		560		2,637		—
December 31, 2007	1,997		140		932		3,069		—

(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 fourteen percent of the proved developed reserves at December 31, 2007 are nonproducing. Plans are to begin producing these reserves in 2008.

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, except in those instances where future oil or natural gas sales are covered by physical contract terms providing for higher or lower prices, to Occidental’s share of estimated annual future production from proved oil and gas reserves, net of royalties. Derivative instruments that qualify as cash flow hedges have not been included in the estimates of future net cash flows. 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, 2007, 2006 and 2005. 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 2007, 2006 and 2005 disclosures, the West Texas Intermediate oil prices used were $95.98 per barrel, $61.05 per barrel and $61.04 per barrel, respectively. The Henry Hub gas prices used for the 2007, 2006 and 2005 disclosures were $6.795/MMBtu, $5.64/MMBtu and $10.08/MMBtu, respectively.

Standardized Measure of Discounted Future Net Cash Flows

In millions

	Consolidated Subsidiaries
	United States			Latin America			Middle East/ North Africa			Total			Other Interests		^(a)
AT DECEMBER 31,2007
Future cash flows	$	169,836		$	11,433		$	25,195		$	206,464		$	(187	)
Future costs
Production costs and other operating
expenses		(59,832	)		(3,432	)		(4,949	)		(68,213	)		74
Development costs ^(b)		(6,166	)		(1,407	)		(1,927	)		(9,500	)		(24	)
Future income tax expense		(35,543	)		(2,171	)		(1,164	)		(38,878	)		112
Future net cash flows		68,295			4,423			17,155			89,873			(25	)
Ten percent discount factor		(40,043	)		(1,387	)		(6,145	)		(47,575	)		5
Standardized measure	$	28,252		$	3,036		$	11,010		$	42,298		$	(20	)
AT DECEMBER 31, 2006
Future cash flows	$	101,755		$	9,279		$	18,436		$	129,470		$	1,139
Future costs
Production costs and other operating
expenses		(49,652	)		(3,002	)		(4,676	)		(57,330	)		(980	)
Development costs ^(b)		(4,240	)		(1,213	)		(1,359	)		(6,812	)		(85	)
Future income tax expense		(16,119	)		(1,778	)		(325	)		(18,222	)		44
Future net cash flows		31,744			3,286			12,076			47,106			118
Ten percent discount factor		(17,428	)		(1,178	)		(4,441	)		(23,047	)		(17	)
Standardized measure	$	14,316		$	2,108		$	7,635		$	24,059		$	101
AT DECEMBER 31, 2005
Future cash flows	$	103,993		$	2,675		$	15,574		$	122,242		$	1,695
Future costs
Production costs and other operating
expenses		(43,587	)		(830	)		(3,559	)		(47,976	)		(1,317	)
Development costs ^(b)		(3,201	)		(86	)		(1,096	)		(4,383	)		(118	)
Future income tax expense		(19,109	)		(880	)		—			(19,989	)		(8	)
Future net cash flows		38,096			879			10,919			49,894			252
Ten percent discount factor		(21,411	)		(223	)		(4,463	)		(26,097	)		(53	)
Standardized measure	$	16,685		$	656		$	6,456		$	23,797		$	199

(a)

The 2007 amounts reflect the minority interest in a Colombian subsidiary, partially offset by Occidental's share of the future net cash flows from an equity investee in Yemen. The 2006 and 2005 amounts include Occidental’s share of the future net cash flows from an equity investee in Yemen and a Russian joint venture, partially offset by the minority interest in a Colombian subsidiary. Occidental's joint venture interest in Russia was sold in 2007.

(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,	2007			2006			2005
Beginning of year	$	24,059		$	23,797		$	14,805
Sales and transfers of oil and gas produced, net of production costs and other operating expenses		(9,553	)		(8,326	)		(6,403	)
Net change in prices received per barrel, net of production costs and other operating expenses		29,396			(3,540	)		12,978
Extensions, discoveries and improved recovery, net of future production and development costs		6,650			2,647			3,014
Change in estimated future development costs		(3,345	)		(2,580	)		(1,561	)
Revisions of quantity estimates		(2,152	)		1,260			(1,135	)
Development costs incurred during the period		3,054			2,449			1,810
Accretion of discount		3,089			3,176			1,933
Net change in income taxes		(8,832	)		388			(3,842	)
Purchases and sales of reserves in place, net		1,817			4,186			2,041
Changes in production rates and other		(1,885	)		602			157
Net change		18,239			262			8,992
End of year	$	42,298		$	24,059		$	23,797

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, 2007, 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			Total		Other Interests ^(c)
2007
Oil	—	Average sales price ($/bbl.)	$	65.67	$	56.66	$	69.24	^(d)	$	64.86	$	68.74	^(d)
Gas	—	Average sales price ($/Mcf)	$	6.53	$	2.66	$	0.99		$	5.68	$	—
Average oil and gas production cost ($/bbl.) ^(b)			$	14.81	$	10.74	$	8.91		$	12.87	$	14.44
2006
Oil	—	Average sales price ($/bbl.)	$	57.84	$	52.40	$	61.58	^(d)	$	57.81	$	62.59	^(d)
Gas	—	Average sales price ($/Mcf)	$	6.49	$	2.00	$	0.97		$	6.00	$	—
Average oil and gas production cost ($/bbl.) ^(b)			$	13.22	$	10.02	$	8.22		$	11.70	$	15.40
2005
Oil	—	Average sales price ($/bbl.)	$	50.12	$	51.18	$	49.88	^(d)	$	50.19	$	50.42	^(d)
Gas	—	Average sales price ($/Mcf)	$	7.10	$	—	$	0.96		$	6.64	$	—
Average oil and gas production cost ($/bbl.) ^(b)			$	10.79	$	5.69	$	5.54		$	9.25	$	19.76

(a)	Sales prices include royalties with respect to certain of Occidental’s interests.
(b)	Natural gas volumes have been converted to BOE based on energy content of six Mcf of gas to one barrel of oil.
(c)	Includes prices and costs applicable to the equity investee in Yemen. Occidental's joint venture interest in Russia was sold in 2007, and all years exclude the prices and costs applicable to the joint venture interest in Russia.
(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, 2007, 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)
2007
Oil	—	Exploratory	2.5	9.0	—	—	11.5	—
		Development	383.1	335.0	114.8	—	832.9	(20.3	)
Gas	—	Exploratory	—	—	—	—	—	—
		Development	84.7	—	8.5	—	93.2	—
Dry	—	Exploratory	4.5	0.5	1.7	—	6.7	—
		Development	1.4	0.8	2.4	—	4.6	0.2
2006
Oil	—	Exploratory	0.5	11.0	2.4	0.2	14.1	—
		Development	437.9	173.9	75.6	—	687.4	(1.4	)
Gas	—	Exploratory	—	—	2.1	—	2.1	—
		Development	124.7	—	—	—	124.7	—
Dry	—	Exploratory	4.7	0.4	2.3	0.3	7.7	0.4
		Development	21.5	4.0	3.7	—	29.2	—
2005
Oil	—	Exploratory	1.5	1.6	4.7	0.2	8.0	(0.3	)
		Development	374.4	20.2	102.6	—	497.2	(0.1	)
Gas	—	Exploratory	—	—	—	—	—	—
		Development	104.3	—	—	—	104.3	—
Dry	—	Exploratory	2.5	2.0	2.9	1.5	8.9	(0.4	)
		Development	13.1	1.0	4.9	—	19.0	—

(a)

The 2007 amounts reflect the minority interest in a Colombian subsidiary, partially offset by Occidental's share of the amounts applicable from an equity investee in Yemen. The 2006 and 2005 amounts include Occidental’s share of the amounts applicable from an equity investee in Yemen and a Russian joint venture, partially offset by the minority interest in a Colombian subsidiary. Occidental's joint venture interest in Russia was sold in 2007.

Productive Oil and Gas Wells

The following table sets forth, as of December 31, 2007, Occidental’s productive oil and gas wells (both producing and capable of production).

Consolidated Subsidiaries

Wells at December 31, 2007

United

States

^(d)

Latin

America

^(d)

Middle

East/

North Africa

^(d)

Total

^(d)

Other

Interests

^(c)

Oil

—

Gross ^(a)

23,697

(701)

3,333

(2,388)

1,338

(19)

28,368

(3,108)

(—)

Net ^(b)

16,782

(480)

2,594

(2,135)

660

(12)

20,036

(2,627)

(21

)

(—)

Gas

—

Gross ^(a)

3,350

(197)

190

(161)

(2)

3,596

(360)

—

(—)

Net ^(b)

2,841

(132)

188

(161)

(2)

3,060

(295)

—

(—)

(a)	The total number of wells in which interests are owned.
(b)	The sum of fractional interests.
(c)	The 2007 amounts reflect the minority interest in a Colombian subsidiary, partially offset by Occidental's share of the amounts applicable from an equity investee in Yemen. The 2006 and 2005 amounts include Occidental’s share of the amounts applicable from an equity investee in Yemen and a Russian joint venture, partially offset by the minority interest in a Colombian subsidiary. Occidental's joint venture interest in Russia was sold in 2007.
(d)	The numbers in parentheses indicate the number of wells with multiple completions.

Participation in Exploratory and Development Wells Being Drilled

The following table sets forth, as of December 31, 2007, Occidental’s participation in exploratory and development wells being drilled.

			Consolidated Subsidiaries
Wells at December 31, 2007			United States	Latin America	Middle East/ North Africa	Total	Other Interests	^(a)
Exploratory and development wells
	—	Gross	59	19	20	98	1
	—	Net	50	15	9	74	—

(a)

At December 31, 2007, Occidental was participating in 117 pressure maintenance projects in the United States, 12 in Latin America and 29 in the Middle East/North Africa.

Oil and Gas Acreage

The following table sets forth, as of December 31, 2007, Occidental’s holdings of developed and undeveloped oil and gas acreage.

Consolidated Subsidiaries

Thousands of acres at

December 31, 2007

United

States

Latin

America

Middle

East/

North Africa

Other

Eastern

Hemisphere

Total

Other

Interests

^(e)

Developed ^(a)

—

Gross ^(b)

5,076

570

1,234

—

6,880

Net ^(c)

3,337

496

529

—

4,362

Undeveloped ^(d)

—

Gross ^(b)

1,723

3,981

34,409

2,409

42,522

—

Net ^(c)

1,133

3,631

24,960

722

30,446

(213

)

(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)	The 2007 amounts reflect the minority interest in a Colombian subsidiary, partially offset by Occidental's share of the amounts applicable from an equity investee in Yemen. Occidental's joint venture interest in Russia was sold in 2007, and the 2007 amounts exclude the amounts applicable from the joint venture interest in Russia.

Oil and Natural Gas Production Per Day

The following table sets forth, for each of the three years in the period ended December 31, 2007, Occidental’s oil, NGLs and natural gas production per day.

	2007		2006		2005
United States
Crude oil and liquids (MBBL)
California	89		86		76
Permian	167		167		161
Hugoton and other	4		3		3
TOTAL	260		256		240
Natural Gas (MMCF)
California	254		256		242
Hugoton and other	153		138		133
Permian	186		194		170
TOTAL	593		588		545
Latin America
Crude oil (MBBL)
Argentina	32		33		—
Colombia	42		38		36
TOTAL	74		71		36
Natural Gas (MMCF)
Argentina	22		17		—
Bolivia	18		17		—
TOTAL	40		34		—
Middle East/North Africa
Crude oil (MBBL)
Oman	20		18		17
Dolphin	4		—		—
Qatar	48		43		42
Yemen	25		29		28
Libya	22		23		8
TOTAL	119		113		95
Natural Gas (MMCF)
Oman	30		30		44
Dolphin	51		—		—
TOTAL	81		30		44
Barrels of Oil Equivalent (MBOE) ^(a)
Subtotal consolidated subsidiaries	573		549		469
Colombia – minority interest	(5	)	(5	)	(4	)
Yemen – Occidental net interest	2		1		1
Total worldwide production ^(b)	570		545		466

(a)

Natural gas volumes have been converted to BOE based on energy content of six Mcf of gas to one barrel of oil.

(b)

Occidental has classified its Pakistan, Horn Mountain and Ecuador operations as discontinued operations on a retrospective application basis and excluded them from this table. Excluded production from Pakistan operations averaged 17,000 BOE per day in 2006 and 18,000 BOE per day in 2005. Excluded production from Horn Mountain operations averaged 13,000 BOE per day in 2006 and 14,000 BOE per day in 2005. Excluded production from Ecuador operations averaged 43,000 BOE per day for the first five months of 2006 and 42,000 BOE per day in 2005. Also excluded is production from a Russian joint venture, which averaged 27,000 BOE per day and 28,000 BOE per day in 2006 and 2005, respectively.

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
2007
Allowance for doubtful accounts	$	15	$	7	$	13		$	—		$	35
Environmental	$	412	$	108	$	5	^(a)	$	(68	)^(b)	$	457
Foreign and other taxes, litigation and other reserves		323		11		10			(171	)^(c)		173
	$	735	$	119	$	15		$	(239	)	$	630	^(d)
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	^(e)		(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	)^(f)		227
	$	1,436	$	106	$	62		$	(959	)	$	645	^(d)

(a)	Primarily represents acquisitions.
(b)	Primarily represents payments.
(c)	Primarily represents reversal of liabilities for unrecognized tax benefits due to Occidental's adoption of FIN No. 48.
(d)	Of these amounts, $123 million, $139 million and $138 million in 2007, 2006 and 2005, respectively, are classified as current.
(e)	Primarily represents acquisitions and balance sheet reclassifications.
(f)	Includes reversal of tax reserves of $874 million.

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 Chairman of the Board and Chief Executive Officer and President 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 Chairman of the Board and Chief Executive Officer and President and Chief Financial Officer concluded that Occidental's disclosure controls and procedures were effective as of December 31, 2007.

There has been no change in Occidental's internal control over financial reporting during the fourth quarter of 2007 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 Chairman of the Board and Chief Executive Officer, President and Chief Financial Officer, Principal 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 2009" in Occidental's definitive proxy statement filed in connection with its May 2, 2008, Annual Meeting of Stockholders (2008 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 2008 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 2008 Proxy Statement. See also the information under "Securities Authorized for Issuance Under Equity Compensation Plans" in Part II, Item 5 of this report.

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 2008 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 2008 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 the Current Report on Form 8-K of Occidental 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 (filed as Exhibit 3.(i)(b) to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2006, File No.1-9210).
3.(ii)*	Bylaws of Occidental, as amended through May 3, 2007 (filed as Exhibit 3.(ii) to the Current Report on Form 8-K of Occidental dated May 4, 2007 (date of earliest event reported), 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 10.82 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 July 19, 2007, between Occidental and Dr. Ray R. Irani (filed as Exhibit 10.4 to the Current Report on Form 8-K of Occidental dated July 18, 2007 (date of earliest event reported), 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).
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).

_________________________

* Incorporated herein by reference

10.9*	Amendment No. 1 to Occidental Petroleum Corporation Modified Deferred Compensation Plan, effective as of January 1, 2007 (filed as Exhibit 10.9 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2006, File No. 1-9210).
10.10	Amendment No. 2 to Occidental Petroleum Corporation Modified Deferred Compensation Plan.
10.11*	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).
10.12*	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).
10.13*	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).
10.14*	Occidental Petroleum Corporation 1996 Restricted Stock Plan for Non-Employee Directors, amended October 11, 2007 (filed as Exhibit 10.1 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended September 30, 2007, File No. 1-9210).
10.15*	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).
10.16*	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).
10.17*	Amendment to Form of Restricted Stock Agreement under Occidental Petroleum Corporation 1996 Restricted Stock Plan for Non-Employee Directors (filed as Exhibit 10.2 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended September 30, 2007, File No. 1-9210).
10.18*	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).
10.19*	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.
10.20	Occidental Petroleum Corporation Supplemental Retirement Plan II.
10.21	Amendment Number 1 to Occidental Petroleum Corporation Supplemental Retirement Plan II.
10.22	Amendment Number 2 to Occidental Petroleum Corporation Supplemental Retirement Plan II.
10.23	Amendment Number 3 to Occidental Petroleum Corporation Supplemental Retirement Plan II.
10.24*	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).
10.25*	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).
10.26*	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).
10.27*	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).
10.28*	Form of Nonqualified Stock Option Agreement under Occidental Petroleum Corporation 2001 Incentive Compensation Plan (July 2002 version) (filed as Exhibit 10.5 to the Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2002, File No. 1-9210).
10.29*	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).
10.30*	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).
10.31*	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).

_________________________

* Incorporated herein by reference

10.32*	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).
10.33*	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).
10.34*	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).
10.35*	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).
10.36*	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).
10.37*	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).
10.38*	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).
10.39*	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).
10.40*	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).
10.41*	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).
10.42*	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).
10.43*	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).
10.44*	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).
10.45*	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).
10.46*	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).
10.47*	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).
10.48*	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).
10.49*	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).
10.50*	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).
10.51*	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).

_________________________

* Incorporated herein by reference

10.52*	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).
10.53*	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).
10.54*	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).
10.55*	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).
10.56*	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).
10.57*	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).
10.58*	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).
10.59*	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).
10.60*	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).
10.61*	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).
10.62*	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).
10.63*	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).
10.64*	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).
10.65*	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).
10.66*	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).
10.67*	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).
10.68*	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).
10.69*	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).
10.70*	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)
10.71*	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 10-K of Occidental dated February 16, 2006 (date of earliest event reported), filed February 22, 2006, File No. 1-9210)
10.72*	Amendment to Form of Restricted Stock Award for Non-Employee Directors under Occidental Petroleum Corporation 2005 Long-Term Incentive Plan (filed as Exhibit 10.3 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended September 30, 2007, File No. 1-9210)

_________________________

* Incorporated herein by reference

10.73*	Form of Restricted Stock Award for Non-Employee Directors under Occidental Petroleum Corporation 2005 Long-Term Incentive Plan (2007 version) (filed as Exhibit 10.4 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended September 30, 2007, File No. 1-9210)
10.74*	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)
10.75*	Terms and Conditions of Performance-Based Stock Award under Occidental Petroleum Corporation 2005 Long-Term Incentive Plan (January 2007 version – Corporate) (filed as Exhibit 10.68 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2006, File No. 1-9210).
10.76*	Terms and Conditions of Performance-Based Stock Award under Occidental Petroleum Corporation 2005 Long-Term Incentive Plan (January 2007 version – Oil and Gas) (filed as Exhibit 10.69 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2006, File No. 1-9210).
10.77*	Terms and Conditions of Performance-Based Stock Award under Occidental Petroleum Corporation 2005 Long-Term Incentive Plan (January 2007 version – Chemicals) (filed as Exhibit 10.70 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2006, File No. 1-9210).
10.78*	Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Return On Equity Incentive Award (Cash-based, Cash-settled Award) (filed as Exhibit 10.1 to the Current Report on Form 8-K of Occidental dated July 18, 2007 (date of earliest event reported), File No. 1-9210).
10.79*	Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Total Shareholder Return Incentive Award Agreement (Equity-based, Equity and Cash-Settled Award) (filed as Exhibit 10.2 to the Current Report on Form 8-K of Occidental dated July 18, 2007 (date of earliest event reported), File No. 1-9210).
10.80*	Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Long-Term Incentive Award Agreement (Equity-based, Cash-Settled Award) (filed as Exhibit 10.3 to the Current Report on Form 8-K of Occidental dated July 18, 2007 (date of earliest event reported), File No. 1-9210).
10.81*	Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Occidental Oil And Gas Corporation Return On Assets Incentive Award Agreement (Cash-Based, Cash-Settled Award) (filed as Exhibit 10.5 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended June 30, 2007, File No. 1-9210).
10.82*	Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Occidental Chemical Corporation Return On Assets Incentive Award Agreement (Cash-Based, Cash-Settled Award) (filed as Exhibit 10.6 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended June 30, 2007, 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, 2007.
21	List of subsidiaries of Occidental at December 31, 2007.
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 22, 2008

By:

/s/ RAY R. IRANI

Ray R. Irani

Chairman of the Board of Directors

and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Title	Date
/s/ RAY R. IRANI	Chairman of the Board of Directors	February 22, 2008
Ray R. Irani	and Chief Executive Officer
/s/ STEPHEN I. CHAZEN	President and Chief Financial Officer	February 22, 2008
Stephen I. Chazen
/s/ JIM A. LEONARD	Vice President and Controller	February 22, 2008
Jim A. Leonard	(Principal Accounting Officer)
/s/ SPENCER ABRAHAM	Director	February 22, 2008
Spencer Abraham
/s/ RONALD W. BURKLE	Director	February 22, 2008
Ronald W. Burkle
/s/ JOHN S. CHALSTY	Director	February 22, 2008
John S. Chalsty
/s/ EDWARD P. DJEREJIAN	Director	February 22, 2008
Edward P. Djerejian
/s/ R. CHAD DREIER	Director	February 22, 2008
R. Chad Dreier
/s/ JOHN E. FEICK	Director	February 22, 2008
John E. Feick

Signature	Title	Date
/s/ IRVIN W. MALONEY	Director	February 22, 2008
Irvin W. Maloney
/s/ RODOLFO SEGOVIA	Director	February 22, 2008
Rodolfo Segovia
/s/ AZIZ D. SYRIANI	Director	February 22, 2008
Aziz D. Syriani
/s/ ROSEMARY TOMICH	Director	February 22, 2008
Rosemary Tomich
/s/ WALTER L. WEISMAN	Director	February 22, 2008
Walter L. Weisman

This report was printed on recycled paper.

EXHIBITS

10.10	Amendment No. 2 to Occidental Petroleum Corporation Modified Deferred Compensation Plan.
10.20	Occidental Petroleum Corporation Supplemental Retirement Plan II.
10.21	Amendment Number 1 to Occidental Petroleum Corporation Supplemental Retirement Plan II.
10.22	Amendment Number 2 to Occidental Petroleum Corporation Supplemental Retirement Plan II.
10.23	Amendment Number 3 to Occidental Petroleum Corporation Supplemental Retirement Plan II.
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, 2007.
21	List of subsidiaries of Occidental at December 31, 2007.
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.

Exhibit 10.10

EXHIBIT 10.10

AMENDMENT NUMBER 2

OCCIDENTAL PETROLEUM CORPORATION

MODIFIED DEFERRED COMPENSATION PLAN

WHEREAS, Occidental Petroleum Corporation (the “Corporation”) maintains the Occidental Petroleum Corporation Modified Deferred Compensation Plan (the “MDCP”) for the purpose of providing a tax-deferred opportunity for key management and highly compensated employees of the Corporation and its affiliates to accumulate additional retirement income through deferrals of cash compensation;

WHEREAS, it is desirable to amend the MDCP to make certain administrative changes.

NOW, THEREFORE, effective January 1, 2008, the MDCP is amended as follows:

1.	Sections 4.1(a) and (b) are amended in their entirety to provide as follows:

“(a) Deferral Elections. An Eligible Employee may elect to participate in the Plan and elect to defer annual Base Salary and/or Bonus under the Plan by filing with the Committee a completed and fully executed Deferral Election Form prior to the beginning of the Plan Year during which the Eligible Employee performs the services for which such Base Salary and Bonus are to be earned, or at such other time as the Committee may permit in accordance with the regulations promulgated under Section 409A of the Code. Deferral Election Forms must be filed in accordance with the instructions set forth in the Deferral Election Forms.

An employee who first becomes an Eligible Employee during a Plan Year may make an initial deferral election under this Plan within 30 days after the date the employee becomes an Eligible Employee provided that such Eligible Employee has not previously become eligible to participate in any other account balance plan of the Company as described in Proposed Treasury Regulations Section 1.409A-1(c)(2) or any successor regulation. Any such election shall apply to Base Salary earned for services performed after the 30-day election window described in the previous sentence and to that portion of the Bonus earned during such Plan Year equal to the total amount of the Bonus multiplied by the ratio of the number of days remaining in the Plan Year after the 30-day election window described in the previous sentence ends over the total number of days during the Plan Year that such Eligible Employee is employed by the Company.

Various deferral options will be made available to Eligible Employees under the Plan, subject to such limitations and

conditions as the Committee may impose from time to time, in its complete and sole discretion. A Deferral Election Form filed for a Plan Year shall be effective for Base Salary and/or Bonus to be earned during that Plan Year only. For each subsequent Plan Year, an Eligible Employee who wishes to defer Base Salary and/or Bonus must file a new complete and fully executed Deferral Election Form in accordance with the instructions set forth in the Deferral Election Form but in any event prior to January 1 of such Plan Year.

Each Deferral Election Form will designate the DCP Deferral Amounts as a fixed dollar amount or fixed percentage (in increments of 1%) of Base Salary and/or (i) a fixed dollar amount or a fixed percentage of Bonus or (ii) 100% of any Bonus exceeding a specified dollar amount, as elected by the Participant. Deferrals of Base Salary will normally be deducted ratably during the Plan Year. In its sole discretion, the Committee may also permit amounts that an Eligible Employee has previously elected to defer under other plans or agreements with the Company to be transferred to this Plan and credited to his Deferral Accounts that are maintained hereunder.

(A) Minimum Deferral. For each Plan Year, the minimum amount of Base Salary that a Participant may elect to defer is $5,000, if expressed as a dollar amount, or 5% of Base Salary, if expressed as a percentage, and the minimum amount of Bonus that a Participant may elect to defer is any of the following: (I) $5,000, (II) 5% of Bonus, or (III) 100% of that portion of any Bonus that exceeds a dollar amount specified by the Participant on his Deferral Election Form.

(B) Maximum Deferral. For each Plan Year, the maximum amount of Base Salary that a Participant may elect to defer is 75% of Base Salary, and the maximum amount of Bonus that a Participant may elect to defer is 90% of Bonus. Notwithstanding the foregoing, effective with respect to amounts earned on or after January 1, 2007, for each Plan Year, the maximum total amount of Compensation that a Participant may elect to defer is $75,000. For the 2007 Plan Year, the $75,000 limit shall apply only to deferrals of Base Salary that would otherwise have been paid in 2007. For the 2008 Plan Year, the $75,000 limit shall apply to the deferrals of Base Salary that would have otherwise been paid in 2008 plus deferrals of Bonus, earned in 2007, and otherwise paid in 2008. For the 2008 Plan Year, the $75,000 limit shall also apply to

deferrals of Base Salary that would have otherwise been paid in 2008 plus deferrals of Bonus, earned in 2008, and otherwise paid in 2009. For the 2009 and all future Plan Years, the $75,000 limit shall apply to amounts of Base Salary and Bonus earned in any one Plan Year. For example, in Plan Year 2009 , the $75,000 limit shall first apply to deferrals of Base Salary that would have otherwise been paid in 2009 and then to deferrals of Bonus that are earned in 2009 and would otherwise be payable in 2010.

(C) Deferral Account Balance. Notwithstanding anything herein to the contrary, if as of December 31 of any Plan Year, a Participant’s total Deferral Account balance is $1,000,000 or more, then the Participant may not defer any compensation earned in the following Plan Year and any election to do so shall be considered void. If as of December 31 of any Plan Year, a Participant’s total Deferral Account balance is less than $1,000,000, then the Participant may defer compensation earned in the following Plan Year in accordance with this Article IV.

(b) Early Payment Benefit Election. With respect to Base Salary and/or Bonus earned after December 31, 2007, on the Deferral Election Form filed pursuant to Section 4.1(a), an Eligible Employee may irrevocably elect to receive the Base Salary and/or Bonus deferred pursuant to that election in a lump sum payment or in annual installments over two (2) to five (5) years commencing prior to termination of employment in an Early Payment Year. If a Participant fails to designate the form of distribution for an Early Payment Benefit, the distribution shall be in the form of a lump sum. The Early Payment Year elected must be a year that begins at least two (2) years after the end of each Plan Year to which the election applies. An Early Payment Benefit election filed for the Plan Year beginning January 1, 2008, or for any subsequent Plan Year, shall be effective for the deferred Base Salary and/or Bonus earned during that Plan Year. A Participant may make an election for an Early Payment Benefit with respect to deferred Base Salary and/or Bonus earned in any future Plan Year by filing a new Deferral Election Form with the Committee prior to January 1 of such Plan Year. A Participant may not, however, change the form of benefit or time of commencement of an Early Payment Benefit with respect to Base Salary and/or Bonus deferred pursuant to a Deferral Election Form after that Deferral Election is filed pursuant to Section 4.1(a).

A Participant may not at any time have Early Payment Benefits scheduled for more than two Early Payment Years.

However, after an Early Payment Year has occurred and all payments with respect to the corresponding Early Payment Year election have been completed, a Participant may elect a new Early Payment Year for future deferrals of Base Salary and/or Bonuses.”

2.	Section 4.4 is amended in its entirety to provide as follows:

“4.4 Interest. Each Deferral Account of a Participant shall be deemed to bear interest on the monthly balance of such Deferral Account at the Declared Rate for each Plan Year, compounded monthly. Except as provided in Section 5.2(a), with respect to SEDCP Deferral Accounts for Participants who die prior to becoming eligible for Retirement, interest will be credited to each Deferral Account on a monthly basis on the last day of each month as long as any amount remains credited to such Deferral Account. Amounts of deferred Compensation that are credited to a DCP Deferral Account and amounts of Savings Plan Restoration Contributions that are credited to a Savings Plan Restoration Account prior to the end of a calendar month shall accrue interest from the date of crediting, computed from date of crediting to the end of the month.”

IN WITNESS WHEREOF, the Corporation has caused its duly authorized officer to execute this amendment this ______ day of _____________, 2007.

OCCIDENTAL PETROLEUM CORPORATION
By:
Richard W. Hallock
Executive Vice-President, Human Resources

Exhibit 10.20

EXHIBIT 10.20

Occidental Petroleum Corporation

Supplemental Retirement Plan II

Effective as of January 1, 2005

Contents

Article 1. Introduction	1
1.1 Establishment and Purpose	1
1.2 Status of the Plan	1
1.3 Application of the Plan	2
Article 2. Definitions	3
2.1 Definitions	3
Article 3. Participation	9
3.1 Effective Date of Participation	9
Article 4. Benefits	10
4.1 Allocations Relating to the Retirement Plan	10
4.2 Allocations Relating to the Savings Plan	11
4.3 Allocations Relating to the Deferred Compensation Plan	12
4.4 Maintenance of Accounts	12
4.5 Vesting and Forfeiture	13
Article 5. Payments	14
5.1 Earliest Time for Distributions	14
5.2 Election of Time and Form of Payment	14
5.3 No Acceleration of Payments	15
5.4 Death	16
5.5 Tax Withholding	16
Article 6. Administration	17
6.1 The Administrative Committee	17
6.2 Compensation and Expenses	17
6.3 Manner of Action	17
6.4 Chairman, Secretary, and Employment of Specialists	17
6.5 Subcommittees	17
6.6 Other Agents	18
6.7 Records	18
6.8 Rules	18

6.9 Powers and Duties	18
6.10 Decisions Conclusive	18
6.11 Fiduciaries	19
6.12 Notice of Address	19
6.13 Data	19
6.14 Adjustments	19
6.15 Member’s Own Participation	20
6.16 Indemnification	20
Article 7. Amendment and Termination	22
7.1 Amendment and Termination	22
7.2 Reorganization of Employer	22
7.3 Protected Benefits	22
Article 8. Claims and Appeals Procedures	23
8.1 Application for Benefits	23
8.2 Claims Procedure for Benefits	23
8.3 Limitations on Actions	24
Article 9. General Provisions	26
9.1 Unsecured General Creditor	26
9.2 Trust Fund	26
9.3 Nonassignability	26
9.4 Release from Liability to Participant	26
9.5 Employment Not Guaranteed	27
9.6 Gender, Singular & Plural	27
9.7 Captions	27
9.8 Validity	27
9.9 Notice	27
9.10 Applicable Law	27

Article 1. Introduction

1.1 Establishment and Purpose

Occidental Petroleum Corporation (the “Company”) hereby establishes the Occidental Petroleum Corporation Supplemental Retirement Plan II (the “Plan”) effective as of January 1, 2005. It is the purpose of this Plan to provide eligible Employees with benefits that will compensate them for maximums imposed by law upon contributions to qualified plans. The portion of the Plan reflecting credits to compensate for the maximum limits imposed by Code section 415 is intended to constitute an “excess plan” as defined in ERISA section 3(36). The remaining portion of the Plan is intended to constitute a plan which is unfunded and maintained primarily for the purpose of providing deferred compensation to a select group of management or highly compensated employees and is intended to meet the exemptions provided in ERISA sections 201(2), 301(a)(3), and 401(a)(1), as well as the requirements of Department of Labor Regulation section 2520.104-23. The Plan shall be administered and interpreted so as to meet the requirements of these exemptions and the regulation.

1.2 Status of the Plan

(a)	Nonqualified Plan. The Plan is not qualified within the meaning of Code section 401(a). The Plan is intended to provide an unfunded and unsecured promise to pay money in the future and thus not to involve, pursuant to Treasury Regulation section 1.83-3(e), the transfer of “property” for purposes of Code section 83. Likewise, allocations under this Plan to the account maintained for a Participant, and earnings credited thereon, are not intended to confer an economic benefit upon the Participant nor is the right to the receipt of future benefits under the Plan intended to result in any Participant, Beneficiary or Alternate Payee being in constructive receipt of any amount so as to result in any benefit due under the Plan being includible in the gross income of any Participant, Beneficiary or Alternate Payee in advance of the date on which payment of any benefit due under the Plan is actually made.
(b)	Compliance with Code Section 409A. This Plan is intended to comply with Code section 409A and related regulatory guidance. Therefore, notwithstanding any other provision of this Plan, for allocations under this Plan and earnings credited on such amounts, no Participant, Beneficiary or Alternate Payee shall have a right to receive a payment if that payment would result in making any portion of the Plan benefit subject to federal income tax under Code section 409A before payment of that benefit has actually been made to the Participant, Beneficiary or Alternate Payee. Consistent with the terms of the Plan, the Administrative Committee shall establish rules regarding distribution options that are designed to avoid making any portion of the Plan benefit subject to federal income tax under Code section 409A before payment of that benefit has actually been made.
(c)	No Guarantees of Intended Tax Treatment. The Plan shall be administered and interpreted so as to satisfy the requirements for the intended tax treatment under the Code described in this section. However, the treatment of benefits earned under and

benefits received from this Plan, for purposes of the Code and other applicable tax laws (such as state income and employment tax laws), shall be determined under the Code and other applicable tax laws and no guarantee or commitment is made to any Participant, Beneficiary or Alternate Payee with respect to the treatment of accruals under or benefits payable from the Plan for purposes of the Code and other applicable tax laws.

1.3 Application of the Plan

The terms of the Plan are applicable to eligible Employees employed by an Employer on or after January 1, 2005. All distributions and distribution elections made on or after January 1, 2005 shall be made in accordance with the provisions of this Plan, as amended from time to time.

Article 2. Definitions

2.1 Definitions

Whenever the following words and phrases are used in the Plan with the first letter capitalized, they shall have the meanings specified below, unless the context clearly indicates otherwise:

(a)	“Administrative Committee” means the committee with authority to administer the Plan as provided under section 6.1.
(b)	“Affiliate” means:

(1)	Any corporation or other business organization while it is controlled by or under common control with the Company within the meaning of Code sections 414 and 1563;
(2)	Any member of an affiliated service group within the meaning of Code section 414(m) of which the Company or any Affiliate is a member;
(3)	Any entity which, pursuant to Code section 414(o) and related Treasury regulations, must be aggregated with the Company or any Affiliate for plan qualification purposes; or
(4)	Any corporation, trade or business which is more than 50 percent owned, directly or indirectly, by the Company and which is designated by the Board or, if authorized by the Board, the Administrative Committee as an Affiliate.

(c)	“Alternate Payee” means a former spouse of a Participant who is recognized by a Divorce Order as having a right to receive all, or a portion of, the benefits payable under this Plan with respect to the Participant.
(d)	“Base Pay of Record” means the base salary of an Employee as stated in the payroll records of his Employer, excluding any amounts paid for bonuses, income realized upon exercise of stock options, and any other special pay which the Employer pays to the Employee during the Plan Year, prior to reduction for any deferral of base salary under the Savings Plan, the Deferred Compensation Plan or any other qualified or non-qualified deferred compensation plan or agreement maintained by the Company or Employer and any pretax contributions for welfare and spending account benefits under any plan maintained by the Company or Employer.
	In the case of an LTD Participant, Base Pay of Record means the Participant’s base salary as described above in effect at the time he became disabled, as defined in the Long-Term Disability Plan.
(e)	“Base Pay Paid” means the Employee Base Pay of Record, reduced for any deferral of base salary under the Deferred Compensation Plan.

(f)	“Beneficiary” means the person(s) entitled to receive the Participant’s benefits under the Retirement Plan in the event of the Participant’s death.
	Notwithstanding the foregoing, where an Employee becomes a Participant through merger of another plan into this Plan, “Beneficiary” means the person or persons so designated under such other plan until a new Beneficiary designation is effected under the Retirement Plan by such Employee.
(g)	“Board” means the Board of Directors of the Company.
(h)	“Code” means the Internal Revenue Code of 1986, as amended.
(i)	“Company” means Occidental Petroleum Corporation and any successor thereto.
(j)	“Controlled Group” means each Employer and all entities that must be aggregated with that Employer pursuant to Code sections 414(b), (c), (m), or (o).
(k)	“Divorce Order” means any judgment, decree, or order (including judicial approval of a property settlement agreement) that relates to the settlement of marital property rights between a Participant and his former spouse pursuant to a state domestic relations law (including, without limitation and if applicable, community property law).
(l)	“Deferred Compensation Plan” means the Occidental Petroleum Corporation 2005 Deferred Compensation Plan, as amended from time to time.
(m)	“Employee” means any person who is an Eligible Employee, as defined in the Retirement Plan, or a Transition Eligible Employee, as defined in section 1.34 the Oxy Permian Cash Balance Retirement Plan, as in effect on July 1, 2000.
	Notwithstanding the foregoing, no individual shall be considered an Employee if such individual is not classified as a common-law employee in the employment records of the Employer, without regard to whether the individual is subsequently determined to have been a common-law employee of the Employer. The persons excluded by this paragraph from being Employees are to be interpreted broadly to include and to have at all times included individuals engaged by the Employer to perform services for such entity in a relationship that the entity characterizes as other than an employment relationship, such as where the Employer engages the individual to perform services as an independent contractor or leases the individual’s services from a third party. The exclusion of the individual from being an Employee shall apply even if a determination is subsequently made by the Internal Revenue Service, another governmental agency, a court or other tribunal, after the individual is engaged to perform such services, that the individual is an employee of the Employer for purposes of pertinent Code sections or for any other purpose.
(n)	“Employer” means the Company and any Affiliate which is designated by the Board or the Administrative Committee and which adopts the Plan.

	The Board or, if authorized by the Board, the Administrative Committee may designate any Affiliate as an Employer under this Plan. The Affiliate shall become an Employer and a party to this Plan upon acceptance of such designation effective as of the date specified by the Board or Administrative Committee.
	By accepting such designation or continuing as a party to the Plan, each Employer acknowledges that:

(A)	It is bound by such terms and conditions relating to the Plan as the Company or the Administrative Committee may reasonably require;
(B)	It hereby acknowledges the authority of the Company and the Administrative Committee to review the Affiliate’s compliance procedures and to require changes in such procedures to protect the Plan;
(C)	It has authorized the Company and the Administrative Committee to act on its behalf with respect to Employer matters pertaining to the Plan;
(D)	It will cooperate fully with Plan officials and their agents by providing such information and taking such other actions as they deem appropriate for the efficient administration of the Plan; and
(E)	Its status as an Employer under the Plan is expressly conditioned on its being and continuing to be an Affiliate of the Company.

	Subject to the concurrence of the Board or Administrative Committee, any Affiliate may withdraw from the Plan, and end its status as an Employer hereunder, by communicating to the Administrative Committee its desire to withdraw. Upon withdrawal, which shall be effective as of the date agreed to by the Board or Administrative Committee, as the case may be, and the Affiliate, the Plan shall be considered frozen as to Employees of such Affiliate.
(o)	“ERISA” means the Employee Retirement Income Security Act of 1974, as amended.
(p)	“Key Employee” means an Employee described in Code section 416(i), but only while such Employee is treated as a “specified employee” under regulatory guidance for purposes of Code section 409A(a)(2)(B)(i).
(q)	“LTD Participant” means an Employee:

(1)	Who became disabled under the terms of the Long-Term Disability Plan prior to October 1, 1995; and
(2)	Who, during the Plan Year, is receiving benefits under the Long-Term Disability Plan and who was a highly-compensated employee (as defined in Code section 414(q)) in the year of his commencement of benefits under the Long-Term Disability Plan.

(r)	“Long-Term Disability Plan” means the Occidental Petroleum Corporation Long-Term Disability Plan or, as appropriate to the LTD Participant or context, the Oxy Vinyls, LP Long-Term Disability Plan.
(s)	“Participant”\ means a person meeting the requirements to participate in the Plan set forth in Article 3.
(t)	“Plan Year” means the calendar year.
(u)	“Qualified Divorce Order”means a Divorce Order that:

(1)	Creates or recognizes the existence of an Alternate Payee’s right to, or assigns to an Alternate Payee the right to, receive all or a portion of the benefits payable to a Participant under this Plan;
(2)	Clearly specifies:

(A)	The name and the last known mailing address of the Participant and the name and mailing address of the Alternate Payee covered by the order;
(B)	The amount or percentage of the Participant’s benefits to be paid by this Plan to the Alternate Payee, or the manner in which such amount or percentage is to be determined;
(C)	The number of payments or period to which such order applies; and
(D)	That it applies to this Plan; and

(3)

Does not:

(A)	Require this Plan to provide any type or form of benefit, or any option, not otherwise provided under the Plan;
(B)	Require this Plan to provide increased benefits;
(C)	Require the payment of benefits to an Alternate Payee that are required to be paid to another Alternate Payee under another Divorce Order previously determined to be a Qualified Divorce Order; or
(D)	Require the payment of benefits under this Plan at a time or in a manner that would cause the Plan to fail to satisfy the requirements of Code section 409A (or other applicable section) and any regulations promulgated thereunder or that would otherwise jeopardize the deferred taxation treatment of any amounts under this Plan.

(v)	“Retirement Plan” means the Occidental Petroleum Corporation Retirement Plan, as amended from time to time.

(w)

“Savings Plan” means the Occidental Petroleum Corporation Savings Plan, as amended from time to time.

(x)

“Separation from Service” means a termination of the employment relationship that meets the requirements for a separation from service under regulatory guidance issued pursuant to Code section 409A(a)(2)(A). Pending the issuance of such regulatory guidance, a Participant will be deemed to have a Separation from Service under this Plan if the Participant ceases to be an employee of all of the following:

(1)	An Employer;
(2)	An Affiliate, regardless of whether the Affiliate is an Employer; or
(3)	Any other entity, whether or not incorporated, in which the Company has an ownership interest, and the Administrative Committee has designated that the Participant’s commencement of employment with such entity upon the Participant’s ceasing to be an employee of an entity described in (1) or (2) above will not be deemed to be a Separation from Service for purposes of this Plan, provided that such designation shall be made in writing by the Administrative Committee and shall be communicated to the Participant prior to his commencement of employment with the entity so designated.

	For purposes of the preceding provisions, a Participant who ceases to be an employee of an entity described in (1), (2) or (3) above shall not be deemed to have a Separation from Service if such cessation of employment is followed immediately by his commencement of employment with another entity described in (1), (2) or (3) above.
(y)	“Supplemental Retirement Plan” means the Occidental Petroleum Corporation Supplemental Retirement Plan in effect on December 31, 2004 and as amended from time to time.
(z)	“Threshold Amount” means the amount determined by the Company and communicated to Employees in advance of the Plan Year as the level of annualized Base Pay of Record at which the sum of the following amounts would exceed the dollar limit in effect for the Plan Year under Code section 415(c)(1)(A):

(1)	The Plan Limit, determined under Appendix II of the Savings Plan (or any successor provision), for the Plan Year for a highly compensated employee as defined under Code section 414(q), times the annualized Base Pay of Record;
(2)	6 percent of the annualized Base Pay Paid; and
(3)	The annual employer contributions for the Plan Year that would be made to the Retirement Plan based on the Employee’s annualized Base Pay of Record assuming that the Employee has attained age 35 as of the last day of the Plan Year.

(aa)	“Wage Base” means the dollar amount of wages, within the meaning set forth in Code section 3121(a), upon which the Employer must pay Social Security Old Age, Survivors and Disability taxes for a Plan Year.

Article 3. Participation

3.1 Effective Date of Participation

An Employee shall become a Participant in this Plan, on or after January 1, 2005, on the earliest date that the Employee is described in one or more of the following subsections:

(a)	Any Employee who was a Participant in the Supplemental Retirement Plan and whose account in that plan was not fully vested on December 31, 2004 shall become a Participant in this Plan on January 1, 2005. The nonvested account of such a Participant shall be transferred to and become the account maintained for the Participant under this Plan, as of January 1, 2005.
(b)	Any Employee whose annualized Base Pay of Record exceeds the Threshold Amount for an Employee who will have attained age 35 by the end of the Plan Year shall become a Participant on the first day of the Plan Year or, if later, the first day of the payroll period that the Employee’s annualized Base Pay of Record exceeds the Threshold Amount.
(c)	Any Employee whose annualized Base Pay of Record for the Plan Year exceeds the amount specified in Code section 401(a)(17) as adjusted and in effect for the Plan Year shall become a Participant on the first day of such Plan Year or, if later, the first day of the payroll period that the Employee’s annualized Base Pay of Record exceeds the amount specified in Code section 401(a)(17) as adjusted and in effect for the Plan Year.
(d)	Any Employee shall become a Participant on the date that:

(1)	The Employee is eligible to participate in both the Retirement Plan and the Deferred Compensation Plan, and
(2)	The Employee is eligible to receive a bonus granted under any management incentive compensation plan of an Employer.

(e)	An individual who is an LTD Participant shall become a Participant on January 1, 2005.

Notwithstanding anything contained herein, any Employee who is entitled to receive supplemental retirement benefits upon his retirement pursuant to a written contract of employment between the Employee and the Company or an Affiliate shall be ineligible to be a Participant effective as of the first day of the Plan Year following the effective date of such contractual provision.

Article 4. Benefits

4.1 Allocations Relating to the Retirement Plan

(a)	Eligibility. The following Employees who become Participants shall be provided the allocation for the Plan Year specified in subsection (b):

(1)	An Employee:

(A)	Who is eligible to participate in the Savings Plan and the Retirement Plan for the Plan Year, and
(B)	Whose annualized Base Pay of Record exceeds the Threshold Amount applicable to the Employee for the Plan Year.

If the Employee’s annualized Base Pay of Record increases during the Plan Year such that it exceeds the Threshold Amount, then the Employee will be eligible for the allocation specified in subsection (b) as of the first payroll period for which the Employee’s annualized Based Pay of Record exceeds the Threshold Amount. If the Employee’s annualized Base Pay of Record decreases during the Plan Year such that it no longer exceeds the Threshold Amount, then the Employee shall cease to be eligible for the allocation specified in subsection (b) as of the first payroll period for which the Employee’s annualized Based Pay of Record falls below the Threshold Amount.

(2)

An individual who is an LTD Participant for the Plan Year.

(b)	Allocation Amount.

(1)	Contingent Credit. A credit shall be made as of the last day of each month to a contingent account maintained for each Participant described in subsection (a). The amount of the credit for the month shall be:

(A)	For a Participant who will not attain age 35 as of the last day of the Plan Year, the sum of:

(i)	4 percent of Base Pay of Record for the calendar month below the Wage Base; plus
(ii)	8 percent of Base Pay of Record for the calendar month above the Wage Base.

(B)	For a Participant who will have attained age 35 as of the last day of the Plan Year, the sum of:

(i)	7 percent of Base Pay of Record for the calendar month below the Wage Base; plus

(ii)	12 percent of Base Pay of Record for the calendar month above the Wage Base.

For purposes of calculating contingent allocations under this section, an Employee will have Base Pay of Record above the Wage Base for a calendar month only to the extent that the Employee’s Base Pay of Record for the Plan Year, determined as of the last day of such pay period, is in excess of the Wage Base.

(2)

Reduction Amount. The amounts contingently credited to the account maintained for the Participant during the Plan Year under paragraph (1) shall be reduced as of the last day of the Plan Year, but not below zero, by the amount determined under this paragraph. The reduction amount is intended to be equal to the Employee’s allocation under the Retirement Plan for the Plan Year. After the reduction described in this paragraph, the remaining amount shall be permanently credited to the account maintained for the Participant.

(A)	No reduction shall apply to the account maintained for any Participant, including an LTD Participant, who is not an Employee on the last day of the Plan Year.
(B)	The reduction amount for other Participants shall be equal to the dollar limit in effect for the Plan Year under Code section 415(c)(1)(A) minus sum of the following:

(i)	The Plan Limit, determined under Appendix II of the Savings Plan (or any successor provision) times the Participant’s Base Pay Paid for the Plan Year, and
(ii)	6 percent times the Participant’s Base Pay Paid for the Plan Year.

For purposes of determining the reduction under this subparagraph, no portion of the Participant’s Base Pay Paid for the Plan Year in excess of the amount specified in Code section 401(a)(17) in effect for the Plan Year shall be taken into account. The reduction amount shall not be less than zero.

(3)

Earnings Allocation. The Employer shall also permanently credit earnings on the monthly allocations under paragraph (1) for the Plan Year as if such allocations shared in earnings at the rate and in the manner described in section 4.4. The earning allocation under this paragraph shall not be subject to reduction under paragraph (2).

4.2 Allocations Relating to the Savings Plan

(a)	Eligibility. An Employee who is eligible to participate in the Savings Plan for the Plan Year and whose Base Pay Paid for the Plan Year exceeds the amount specified

	in Code section 401(a)(17) as adjusted and in effect for the Plan Year shall be provided the allocation for the Plan Year specified in subsection (b):
(b)	Allocation Amount. The amount to be allocated as of the last day of the Plan Year under this Plan with respect to a Participant described in subsection (a) above for the Plan Year shall equal the sum of:

(1)	6 percent of the Employee’s Base Pay Paid in excess of the amount specified in Code section 401(a)(17) as adjusted and in effect for the Plan Year; and
(2)	5 percent of the amount allocated under paragraph (1) which shall be allocated to the account maintained for the Participant in lieu of interest on such amount for the Plan Year.

4.3 Allocations Relating to the Deferred Compensation Plan

(a)	Eligibility. An Employee who is a participant in the Retirement Plan and eligible to participate in the Deferred Compensation Plan for the Plan Year shall be provided the allocation for the Plan Year specified in subsection (b).
(b)	Allocation Amount. The amount to be allocated in a Plan Year under this Plan with respect to a Participant described in subsection (a) above for the Plan Year shall equal that Participant’s applicable percentage multiplied by the amount of the bonus the Participant is entitled to elect to defer for that plan year of the Deferred Compensation Plan. This allocation shall be made irrespective of whether such Participant elects to defer under the Deferred Compensation Plan all or any part of any bonus to which he might be entitled. Notwithstanding the preceding sentence, no allocation shall be made to the account of a Participant who is not an Employee on the date that any such bonus is awarded.
	For purposes of this subsection, the term “applicable percentage” shall mean 12 percent in the case of a Participant who shall have attained age 35 prior to the end of the Plan Year in which the allocation is made and 8 percent in the case of a Participant who shall not have attained age 35 prior to the end of the Plan Year in which the allocation is made. The allocation described in this section shall be made to the account of each Participant effective as of the date on which the Participant is awarded the bonus he is entitled to defer under the Deferred Compensation Plan.

4.4 Maintenance of Accounts

(a)

Each Employer shall establish and maintain, in the name of each Participant employed by that Employer, an individual account which shall consist of all amounts credited to the Participant. As of the end of each month, the Administrative Committee shall increase the balance, if any, of the Participant’s individual account as of the last day of the preceding month, by multiplying such amount by a number equal to one plus .167% plus the monthly yield on 5-Year Treasury Constant Maturities for the monthly processing period.

(b)

The individual account of each Participant shall represent a liability, payable when due under this Plan, out of the general assets of the Company, or from the assets of any trust, custodial account or escrow arrangement which the Company may establish for the purpose of assuring availability of funds sufficient to pay benefits under this Plan. The money and any other assets in any such trust or account shall at all times remain the property of the Company, and neither this Plan nor any Participant shall have any beneficial ownership interest in the assets thereof. No property or assets of the Company shall be pledged, encumbered, or otherwise subjected to a lien or security interest for payment of benefits hereunder. Accounting for this Plan shall be based on generally accepted accounting principles.

4.5 Vesting and Forfeiture

Notwithstanding any other Plan provision, all benefits under this Plan shall be contingent and forfeitable and no Participant shall have a vested interest in any benefit unless, while he is still employed by an Employer, he becomes fully vested in his benefit under the Retirement Plan (or would have become vested if he were a participant in the Retirement Plan). A person who terminates employment with an Employer for any reason prior to becoming vested hereunder shall not receive a benefit, provided that, upon rehire by an Employer, any amounts forfeited by a Participant at the time of his termination of employment shall be restored, without interest, to his account.

Article 5. Payments

5.1 Earliest Time for Distributions

(a)	General Rules. A Participant’s vested account under this Plan may not be distributed earlier than:

(1)	The Participant’s Separation from Service;
(2)	The Participant’s death.

(b)	Special Rules. Notwithstanding the foregoing:

(1)	In the case of a Participant who is a Key Employee, a distribution made on account of Separation from Service may not be made before a date that is at least six months after the Participant’s Separation from Service.
(2)	No LTD Participant shall be entitled to a distribution of benefits under this Plan prior to the time long-term disability payments cease.

5.2 Election of Time and Form of Payment

(a)

General Rules. All elections as to the time and form of payment under this Plan shall be made only in accordance with the provisions of this Plan and the rules and procedures established by the Administrative Committee for the time and manner of making elections. If a Participant fails to make a valid and timely election, the vested account, if any, maintained for the Participant shall be paid as a single sum as soon as administratively practicable. In addition, notwithstanding any election made by the Participant under this section, if the balance of the vested account, if any, maintained for the Participant is less than $50,000 when the amount first becomes payable under section 5.1, the balance shall be paid in a single sum as soon as administratively practicable.

(b)

Available Times and Forms of Payment. Subject to the provisions of this Article, the Participant may elect to have his account paid out as follows:

(1)

As single sum during the first calendar quarter following the calendar year in which occurs the distribution event specified in section 5.1, except death, or

(2)

Annual installment payments over 5, 10, 15, or 20 years, as elected by the Participant, commencing during the first calendar quarter following the calendar year in which occurs the distribution event specified in section 5.1, except death, and continuing each year thereafter until the final installment is paid or, if earlier, the Participant dies. While benefits are to be paid in installments, the Participant’s account will continue to be adjusted as provided in section 4.4(a) until the series of installments has been completed. The amount of each annual installment while the Participant is alive shall equal the amount credited to the account as of January 31 of the year in which the installment is to be paid, multiplied by a fraction, the numerator of which is 1,

and the denominator of which is the number of installments (including the current one) which remain to be paid. Each installment shall be paid as soon as administratively possible after January 31 of the calendar year. If the Participant dies while installments remain to be paid, the remaining account credited to the Participant shall be paid to the Beneficiary as soon as practicable following the Participant’s death.

(c)	Transition Rule. If the Employee is a Participant during the 2005 Plan Year, the Participant shall make an election with respect to the time and form of payment of the account maintained for the Participant upon the earlier of the Participant’s Separation from Service or the 60^th day after this Plan is adopted by the Board, but in no event later than December 31, 2005.
(d)	New Participants. Any Employee who becomes a Participant after December 31, 2005 shall make an election with respect to the time and form of payment of the account maintained for the Participant no later than the 30^th day after the Employee first becomes a Participant.
(e)	Change of Elections. A Participant shall not be permitted to change his election as to the time and form of payment, regardless of whether the Participant made an affirmative initial election or the election was defaulted to a single sum because of the Participant’s failure to make a valid and timely election, except as provided in this section.

(1)	Except as provided in section 5.3, no election shall be permitted which accelerates the time of any payment.
(2)	Any change in election resulting in a delay or change in the form of payment shall not take effect until the one-year anniversary of the date the changed election is properly made.
(3)	In the case of a payment on account of the Participant’s Separation from Service, the first payment under the changed election must result in a deferral for a period of at least 5 years from the date the first payment would have been made under the initial election.

5.3 No Acceleration of Payments

The Administrative Committee shall not permit the acceleration of the time or schedule of payments except as provided in this section.

As of January 1, 2005, acceleration of the time or schedule of payments shall be permitted only in the following instances:

(a)	A payment to an Alternate Payee to the extent necessary to fulfill a Qualified Divorce Order;
(b)	A payment that is necessary to comply with a certificate of divestiture as defined in Code section 1043(b)(2); or

(c)

A payment to pay the Federal Insurance Contributions Act (FICA) tax imposed under Code sections 3101 and 3121(v)(2) on amounts held by the Plan as well as a payment to pay any income tax at source on wages imposed under Code section 3401 (i.e., wage withholding) on the FICA tax amount and any income tax at source attributable to the pyramiding wages and taxes. The total payment under this subsection may not exceed the aggregate FICA tax amount and the income tax withholding related to such FICA tax amount.

5.4 Death

The account or, if benefits have commenced, the remaining account of a Participant who dies shall be paid in a single sum to the Participant’s Beneficiary as soon as administratively possible following the date of the Participant’s death.

5.5 Tax Withholding

Any federal, state or local taxes, including FICA tax amounts, required by law to be withheld with respect to benefits earned and vested under this Plan or any other compensation arrangement may be withheld from the Participant’s benefit, salary, wages or other amounts paid by the Company or any Employer and reasonably available for withholding. Prior to making or authorizing any benefit payment under this Plan, the Company may require such documents from any taxing authority, or may require such indemnities or a surety bond from any Participant or Beneficiary, as the Company shall reasonably consider necessary for its protection.

Article 6. Administration

6.1 The Administrative Committee

The Plan shall be administered by an Administrative Committee appointed by the Board. The Administrative Committee shall be composed of as many members as the Board may appoint from time to time, but not fewer than three members, and shall hold office at the discretion of the Board. Such members may, but need not, be Employees of the Company.

Any member of the Administrative Committee may resign by delivering his written resignation to the Board and to the Administrative Committee Secretary. Such resignation shall be effective no earlier than the date of the written notice.

Vacancies in the Administrative Committee arising by resignation, death, removal, or otherwise, shall be filled by the Board.

6.2 Compensation and Expenses

The members of the Administrative Committee who are Employees shall serve without compensation for services as a member. Any member may receive reimbursement by the Company of expenses properly and actually incurred. All expenses of the Administrative Committee shall be paid directly by the Company. Such expenses may include any expenses incident to the functioning of the Administrative Committee, including, but not limited to, fees of the Plan’s accountants, outside counsel and other specialists and other costs of administering the Plan.

6.3 Manner of Action

A majority of the members of the Administrative Committee at the time in office shall constitute a quorum for the transaction of business. All resolutions adopted, and other actions taken by the Administrative Committee at any meeting shall be by the vote of a majority of those present at any such meeting.

Upon obtaining the written consent of a majority of the members at the time in office, action of the Administrative Committee may be taken otherwise than at a meeting.

6.4 Chairman, Secretary, and Employment of Specialists

The members of the Administrative Committee shall elect one of their number as Chairman and shall elect a Secretary who may, but need not, be a member. They may authorize one or more of their number or any agent to execute or deliver any instrument or instruments on their behalf, and may employ such counsel, auditors, and other specialists and such other services as they may require in carrying out the provisions of the Plan.

6.5 Subcommittees

The Administrative Committee may appoint one or more subcommittees and delegate such of its power and duties as it deems desirable to any such subcommittee, in which case every reference herein made to the Administrative Committee shall be deemed to mean or include the subcommittees as to matters within their jurisdiction. The members of any such

subcommittee shall consist of such officers or other employees of the Company and such other persons as the Administrative Committee may appoint.

6.6 Other Agents

The Administrative Committee may also appoint one or more persons or agents to aid it in carrying out its duties as a fiduciary, and delegate such of its powers and duties as it deems desirable to such person or agents.

6.7 Records

All resolutions, proceedings, acts, and determinations of each Committee shall be recorded by the Secretary thereof or under his supervision, and all such records, together with such documents and instruments as may be necessary for the administration of the Plan, shall be preserved in the custody of the Secretary.

6.8 Rules

Subject to the limitations contained in the Plan, the Administrative Committee shall be empowered from time to time in its discretion to adopt by-laws and establish rules for the conduct of its affairs and the exercise of the duties imposed upon it under the Plan.

6.9 Powers and Duties

The Administrative Committee shall have responsibility for the general administration of the Plan and for carrying out its provisions. The Administrative Committee shall have such powers and duties as may be necessary to discharge its functions hereunder, including, but not limited to, the following:

(a)	To construe and interpret the Plan, to supply all omissions from, correct deficiencies in and resolve ambiguities in the language of the Plan; to decide all questions of eligibility and determine the amount, manner, and time of payment of any benefits hereunder;
(b)	To make a determination as to the right of any person to an allocation, and the amount thereof;
(c)	To obtain from the Employees such information as shall be necessary for the proper administration of the Plan and, when appropriate, to furnish such information promptly to other persons entitled thereto;
(d)	To prepare and distribute, in such manner as the Company determines to be appropriate, information explaining the Plan; and
(e)	To establish and maintain such accounts in the name of each Participant as are necessary.

6.10 Decisions Conclusive

The Administrative Committee shall exercise their powers hereunder in a uniform and nondiscriminatory manner. Any and all disputes with respect to the Plan which may arise involving Participants or their Beneficiaries shall be referred to the Administrative

Committee and its decision shall be final, conclusive, and binding. Furthermore, if any question arises as to the meaning, interpretation, or application of any provision hereof, the decision of the Administrative Committee with respect thereto shall be final.

6.11 Fiduciaries

The fiduciaries named in this Article shall have only those specific powers, duties, responsibilities, and obligations as are specifically given them under this Plan. The Company shall have the sole authority to amend or terminate, in whole or in part, this Plan. The Administrative Committee shall be a fiduciary under the Plan and shall have the sole responsibility for the administration of this Plan. The officers and Employees of the Company shall have the responsibility of implementing the Plan and carrying out its provisions as the Administrative Committee shall direct. A fiduciary may rely upon any direction, information, or action of another fiduciary as being proper under this Plan, and is not required under this Plan to inquire into the propriety of any such direction, information, or action. It is intended under this Plan that each fiduciary shall be responsible for the proper exercise of his own powers, duties, responsibilities, and obligations under this Plan and shall not be responsible for any act or failure to act of another fiduciary. No fiduciary guarantees in any manner the payment of benefits from this Plan. Any party may serve in more than one fiduciary capacity with respect to the Plan.

6.12 Notice of Address

Each person entitled to benefits from the Plan must file with the Administrative Committee or its agent, in writing, his mailing address and each change of his mailing address. Any communication, statement, or notice addressed to such a person at his latest reported mailing address will be binding upon him for all purposes of the Plan, and neither the Administrative Committee nor the Company shall be obliged to search for or ascertain his whereabouts.

6.13 Data

All persons entitled to benefits from the Plan must furnish to the Administrative Committee such documents, evidence, or information, including information concerning marital status, as the Administrative Committee considers necessary or desirable for the purpose of administering the Plan. It shall be an express condition of the Plan that each such person must furnish such information and sign such documents as the Administrative Committee may require before any benefits become payable from the Plan. The Administrative Committee shall be entitled to distribute to a non-spouse Beneficiary in reliance upon the signed statement of the Participant that he is unmarried without any further liability to a spouse if such statement is false.

6.14 Adjustments

The Administrative Committee may adjust benefits under the Plan or make such other adjustments with respect to a Participant or Beneficiary as are required to correct administrative errors or provide uniform treatment in a manner consistent with the intent and purposes of the Plan.

6.15 Member’s Own Participation

No member of the Administrative Committee may act, vote or otherwise influence a decision specifically relating to his own participation under the Plan.

6.16 Indemnification

(a)	To the extent permitted by the Company’s bylaws and applicable law, the Company shall indemnify and hold harmless each of the following persons (“Indemnified Persons”) under the terms and conditions of this section:

(1)

The Administrative Committee and each of its members which, for purposes of this section, includes any Employee to whom the Administrative Committee has delegated fiduciary or other duties.

(2)

The Board and each member of the Board of Directors of the Corporation and any Employer who has responsibility (whether by delegation from another person, an allocation of responsibilities under the terms of this Plan document, or otherwise) for a fiduciary duty, a nonfiduciary settlor function (such as deciding whether to approve a plan amendment), or a nonfiduciary administrative task relating to the Plan.

(b)

The Company shall indemnify and hold harmless each Indemnified Person against any and all claims, losses, damages, and expenses, including reasonable attorney’s fees and court costs, incurred by that person on account of his or her good faith actions or failures to act with respect to his or her responsibilities relating to the Plan. The Company’s indemnification shall include payment of any amounts due under a settlement of any lawsuit or investigation, but only if the Company agrees to the settlement.

(1)	An Indemnified Person shall be indemnified under this section only if he or she notifies an Appropriate Person at the Company of any claim asserted against or any investigation of the Indemnified Person that relates to the Indemnified Person’s responsibilities with respect to the Plan.

(A)

A person is an “Appropriate Person” to receive notice of the claim or investigation if a reasonable person would believe that the person notified would initiate action to protect the interests of the Company in response to the Indemnified Person’s notice.

(B)

The notice may be provided orally or in writing. The notice must be provided to the Appropriate Person promptly after the Indemnified Person becomes aware of the claim or investigation. No indemnification shall be provided under this section to the extent that the Company is materially prejudiced by the unreasonable delay of the Indemnified Person in notifying an Appropriate Person of the claim or investigation.

(2)	An Indemnified Person shall be indemnified under this section with respect to attorney’s fees, court costs or other litigation expenses or any settlement of

	such litigation only if the Indemnified Person agrees to permit the Company to select counsel and to conduct the defense of the lawsuit.
(3)	No Indemnified Person shall be indemnified under this section with respect to any action or failure to act that is judicially determined to constitute or be attributable to the willful misconduct of the Indemnified Person.
(4)	Payments of any indemnity under this section shall be made only from insurance or other assets of the Company. The provisions of this section shall not preclude such further indemnities as may be available under insurance purchased by the Company or as may be provided by the Company under any by-law, agreement or otherwise, provided that no expense shall be indemnified under this section that is otherwise indemnified by the Company or by an insurance contract purchased by the Company.

Article 7. Amendment and Termination

7.1 Amendment and Termination

The Company expects the Plan to be permanent, but since future conditions affecting the Company or any Employer cannot be anticipated or foreseen, the Company must necessarily and does hereby reserve the right to amend, modify, or terminate the Plan at any time by action of the Board, except that no amendment shall reduce the dollar amount permanently credited to a Participant’s account and any such termination or amendment shall apply uniformly to all Participants. The Administrative Committee, in its discretion, may amend the Plan if it finds that such amendment does not significantly increase or decrease benefits or costs. Notwithstanding the foregoing, the Board or the Administrative Committee may amend the Plan to:

(a)	Ensure that this Plan complies with the requirements of Code section 409A for deferral of taxation on compensation deferred hereunder until the time of distribution; and
(b)	Add provisions for changes to elections as to time and manner of distributions and other changes that comply with the requirements of Code section 409A for the deferral of taxation on deferred compensation until the time of distribution.

7.2 Reorganization of Employer

In the event of a merger or consolidation of the Employer, or the transfer of substantially all of the assets of the Employer to another corporation, such continuing, resulting or transferee corporation shall have the right to continue and carry on the Plan and to assume all liabilities of the Employer hereunder without obtaining the consent of any Participant or Beneficiary. If such successor shall assume the liabilities of the Employer hereunder, then the Employer shall be relieved of all such liability, and no Participant or Beneficiary shall have the right to assert any claim against the Employer for benefits under or in connection with the Plan.

7.3 Protected Benefits

If the Plan is terminated or amended so as to prevent further earnings adjustments, or if liabilities accrued hereunder up to the date of an event specified in section 7.2 are not assumed by the successor to the Employer, then the dollar amount in the account of each Participant or Beneficiary (whether or not vested) shall be paid in cash to such Participant or Beneficiary in a single sum on the last day of the second month following the month in which the amendment or termination occurs.

Article 8. Claims and Appeals Procedures

8.1 Application for Benefits

All applications for benefits under the Plan shall be submitted to: Occidental Petroleum Corporation, Attention: Administrative Committee, 10889 Wilshire Blvd., Los Angeles, CA 90024. Applications for benefits must be in writing on the forms prescribed by the Administrative Committee and must be signed by the Participant, Beneficiary, spouse, Alternate Payee, or other person claiming benefits under this Plan (each of which may be “Claimant”).

8.2 Claims Procedure for Benefits

(a)	If a Claimant believes he is entitled to a benefit, or a benefit different from the one received, then the Claimant may file a claim for the benefit by writing a letter to the Administrative Committee or its authorized delegate.
(b)	Within a reasonable period of time, but not later than 90 days after receipt of a claim for benefits, the Administrative Committee or its delegate shall notify the Claimant of any adverse benefit determination on the claim, unless special circumstances require an extension of time for processing the claim. In no event may the extension period exceed 90 days from the end of the initial 90-day period. If an extension is necessary, the Administrative Committee or its delegate shall provide the Claimant with a written notice to this effect prior to the expiration of the initial 90-day period. The notice shall describe the special circumstances requiring the extension and the date by which the Administrative Committee or its delegate expects to render a determination on the claim.
(c)	In the case of an adverse benefit determination, the Administrative Committee or its delegate shall provide to the Claimant written or electronic notification setting forth in a manner calculated to be understood by the claimant:

(1)	The specific reason or reasons for the adverse benefit determination;
(2)	Reference to the specific Plan provisions on which the adverse benefit determination is based;
(3)	A description of any additional material or information necessary for the Claimant to perfect the claim and an explanation of why the material or information is necessary; and
(4)	A description of the Plan’s claim review procedures and the time limits applicable to such procedures, including a statement of the Claimant’s right to bring a civil action under Section 502(a) of ERISA following an adverse final benefit determination on review and in accordance with section 8.3.

(d)	Within 60 days after receipt by the Claimant of notification of the adverse benefit determination, the Claimant or his duly authorized representative, upon written application to the Administrative Committee, may request that the Administrative

Committee fully and fairly review the adverse benefit determination. On review of an adverse benefit determination, upon request and free of charge, the Claimant shall have reasonable access to, and copies of, all documents, records and other information relevant to the claimant’s claim for benefits. The Claimant shall have the opportunity to submit written comments, documents, records, and other information relating to the claim for benefits. The Administrative Committee’s (or delegate’s) review shall take into account all comments, documents, records, and other information submitted regardless of whether the information was previously considered in the initial adverse benefit determination.

(e)

Within a reasonable period of time, but not later than 60 days after receipt of such request for review, the Administrative Committee or its delegate shall notify the Claimant of any final benefit determination on the claim, unless special circumstances require an extension of time for processing the claim. In no event may the extension period exceed 60 days from the end of the initial 60-day period. If an extension is necessary, the Administrative Committee or its delegate shall provide the Claimant with a written notice to this effect prior to the expiration of the initial 60-day period. The notice shall describe the special circumstances requiring the extension and the date by which the Administrative Committee or its delegate expects to render a final determination on the request for review. In the case of an adverse final benefit determination, the Administrative Committee or its delegate shall provide to the claimant written or electronic notification setting forth in a manner calculated to be understood by the Claimant:

(1)	The specific reason or reasons for the adverse final benefit determination;
(2)	Reference to the specific Plan provisions on which the adverse final benefit determination is based;
(3)	A statement that the Claimant is entitled to receive, upon request and free of charge, reasonable access to, and copies of, all documents, records and other information relevant to the Claimant’s claim for benefits; and
(4)	A statement of the claimant’s right to bring a civil action under Section 502(a) of ERISA following an adverse final benefit determination on review and in accordance with section 8.3.

8.3 Limitations on Actions

All decisions made under the procedure set out in this Article shall be final and there shall be no further right of appeal. No person may initiate a lawsuit before fully exhausting the claims procedures set out in this Article, including appeal. To provide for an expeditious resolution of any dispute concerning a claim for benefits that has been denied and to ensure that all evidence pertinent to such claim is available, no lawsuit may be brought contesting a denial of benefits more than the later of:

(a)	180 days after receiving the written response of the Administrative Committee to an appeal; or

(b)	365 days after an applicant’s original application for benefits.

Article 9. General Provisions

9.1 Unsecured General Creditor

The rights of a Participant, Beneficiary, Alternate Payee or their heirs, successors, and assigns, as relates to any Company or Employer promises hereunder, shall not be secured by any specific assets of the Company or any Employer, nor shall any assets of the Company or any Employer be designated as attributable or allocated to the satisfaction of such promises.

9.2 Trust Fund

The Company shall be responsible for the payment of all benefits provided under the Plan. At its discretion, the Company may establish one or more trusts, with such trustees as the Board or Administrative Committee may approve, for the purpose of providing for the payment of such benefits. Such trust or trusts may be irrevocable, but the assets thereof shall be subject to the claims of the Company’s creditors. To the extent any benefits provided under the Plan are actually paid from any such trust, the Company shall have no further obligation with respect thereto, but to the extent not so paid, such benefits shall remain the obligation of, and shall be paid by, the Company.

9.3 Nonassignability

(a)

Neither a Participant nor any other person shall have any right to commute, sell, assign, transfer, pledge, anticipate, mortgage or otherwise encumber, hypothecate or convey in advance of actual receipt the amount, if any, payable hereunder, or any part thereof, or interest therein which are, and all rights to which are, expressly declared to be unassignable and non-transferable. No part of the amounts payable shall, prior to actual payment, be subject to seizure or sequestration for the payment of any debts, judgments, alimony or separate maintenance owed by a Participant or any other person, nor be transferable by operation of law in the event of a Participant’s or any other person’s bankruptcy or insolvency.

(b)

Notwithstanding subsection (a), the right to benefits payable with respect to a Participant pursuant to a Qualified Divorce Order may be created, assigned, or recognized. The Administrative Committee shall establish appropriate policies and procedures to determine whether a Divorce Order presented to the Administrative Committee constitutes a qualified Divorce Order under this Plan, and to administer distributions pursuant to the terms of Qualified Divorce Orders. In the event that a Qualified Divorce Order exists with respect to benefits payable under the Plan, such benefits otherwise payable to the Participant specified in the Qualified Divorce Order shall be payable to the Alternate Payee specified in such Qualified Divorce Order.

9.4 Release from Liability to Participant

A Participant’s right to receive benefits under the Plan shall be reduced to the extent that any portion of account maintained for the Participant has been paid or set aside for payment to an Alternate Payee pursuant to a Qualified Divorce Order or to the extent that the Company or the Plan is otherwise subject to a binding judgment, decree, or order for the attachment, garnishment or execution of any portion of the account maintained for the Participant or of

any distributions therefrom. The Participant shall be deemed to have released the Company and the Plan from any claim with respect to such amounts in any case in which:

(a)	The Company, the Plan, or any Plan representative has been served with legal process or otherwise joined in a proceeding relating to such amounts; and
(b)	The Participant fails to obtain an order of the court in the proceeding relieving the Company and the Plan from the obligation to comply with the judgment, decree or order.

9.5 Employment Not Guaranteed

Nothing contained in this Plan nor any action taken hereunder shall be construed as a contract of employment or as giving any Participant any right to be retained in employment with the Company or any Employer. Accordingly, subject to the terms of any written employment agreement to the contrary, the Company and Employer shall have the right to terminate or change the terms of employment of a Participant at any time and for any reason whatsoever, with or without cause.

9.6 Gender, Singular & Plural

All pronouns and any variations thereof shall be deemed to refer to the masculine or feminine as the identity of the person or persons may require. As the context may require, the singular may be read as the plural and the plural as the singular.

9.7 Captions

The captions of the articles, sections, and paragraphs of the Plan are for convenience only and shall not control or affect the meaning or construction of any of its provisions.

9.8 Validity

In the event any provision of this Plan is held invalid, void, or unenforceable, the same shall not affect, in any respect whatsoever, the validity of any other provision of this Plan.

9.9 Notice

Any notice or filing required or permitted to be given to the Administrative Committee under the Plan shall be sufficient if in writing and hand delivered, or sent by registered or certified mail, to the principal office of the Company. Such notice shall be deemed given as to the date of delivery or, if delivery is made by mail, as of the date shown on the postmark on the receipt for registration or certification.

9.10 Applicable Law

The Plan shall be governed by and construed in accordance with Code section 409A (or other applicable section), and any regulations promulgated thereunder, and the laws of the State of California to the extent such laws are not preempted by ERISA.

Exhibit 10.21

EXHIBIT 10.21

AMENDMENT NUMBER 1

TO THE

OCCIDENTAL PETROLEUM CORPORATION

SUPPLEMENTAL RETIREMENT PLAN II

WHEREAS, Occidental Petroleum Corporation (the “Company”) maintains the Occidental Petroleum Corporation Supplemental Retirement Plan II (the “SRPII”), the purpose of which is to provide eligible employees with benefits that would otherwise be provided under the Company’s qualified plans but for the limits imposed by law upon contributions to qualified plans;

WHEREAS, the SRPII is generally intended to comply with the requirements of Section 409A of the Internal Revenue Code and related regulatory guidance (“Section 409A”);

WHEREAS, certain participants who have entered into employment contracts have benefits under the SRPII;

WHEREAS, it is desirable to amend the SRPII to ensure that these benefits do not violate the requirements of Section 409A;

NOW, THEREFORE, effective as of 1^st of January, 2005, the SRPII is hereby amended as follows:

ARTICLE II

DEFINITIONS

1. Section 1.2(b) of the SRPII is amended by adding the following new paragraph at the end thereof:

Notwithstanding the foregoing or anything in the Plan to the contrary, no provision of the Plan (including, without limitation, the permitted acceleration provisions of Section 5.3(a)-(c)), or provision of an amendment to the Plan, that (A) represents a material enhancement of the benefits or rights available under the Occidental Petroleum Corporation Supplemental Retirement Plan (the “Supplemental Retirement Plan”), or (B) adds a new material benefit or right that did not exist under the Supplemental Retirement Plan shall apply with respect to the Plan benefit of any Participant listed on Exhibit A hereto.

2. Section 5.1(b) of the SRPII is amended by adding the following new paragraph (3) at the end thereof:

(3)	No Participant listed on Exhibit B hereto shall be entitled to a distribution of benefits under this Plan prior to the payment date specified in Exhibit B, except in the event of such Participant’s death.

3.	Section 5.2(e) of the SRPII is amended by adding the following new paragraph (4) at the end thereof:

(4)

In the case of a payment to a Participant listed on Exhibit B on the payment date specified in Exhibit B, (A) the change in election must be made at least 12 months prior to such specified payment date and (B) the first payment under the changed election must result in a deferral for a period of at least 5 years from such specified payment date.

4.	The SRPII is amended by adding an Exhibit A thereto to read as follows:

EXHIBIT A

Participants with pre-October 4, 2004 Retainer Agreements

Axelson, Jr., C.J.

Doucet, M.J.

Freund, M.C.

Hull Jr., C.W.

Hurst III, J.L.

Lorraine, R.A.

Oenbring, P.R.

Vincent, P.G.

Watkins, A.A.

5.	The SRPII is amended by adding an Exhibit B thereto to read as follows:

EXHIBIT B

Participants with post-October 3, 2004 Retainer Agreements

Participant	Payment Date
Allen, J.M.	September 30, 2007
Bullock, B.J.	January 31, 2007
LaBelle, D.E.	August 31, 2008
Loving, R.P.	July 31, 2006
Schmitt, R.H.	December 31, 2007
Tayburn, J.W.	August 31, 2006

In Witness Whereof, the Company has caused this amendment to be adopted on its behalf by the unanimous action of the Pension and Retirement Plan Administrative Committee this ____ day of _______________, 2005.

Occidental Petroleum Corporation

Pension and Retirement Plan

Administrative Committee

Richard W. Hallock

Jim A. Leonard

Samuel P. Dominick

Anthony R. Leach

Robert E. Sawyer

Darin S. Moss

Exhibit 10.22

EXHIBIT 10.22

AMENDMENT NUMBER 2

TO THE

OCCIDENTAL PETROLEUM CORPORATION

SUPPLEMENTAL RETIREMENT PLAN II

Effective as of January 1, 2005

The Occidental Petroleum Corporation Supplemental Retirement Plan II (Effective as of January 1, 2005) (“Plan”) is hereby amended as of January 1, 2006 (unless a different effective date is specified), as follows:

1. Section 2.1(f), relating to the definition of “Beneficiary”, is amended in its entirety to read as follows:

“Beneficiary” means the person(s) entitled to receive the Participant’s benefits under the Retirement Plan in the event of the Participant’s death.

Notwithstanding the foregoing, where a Participant has designated a Beneficiary under Appendix A of the Occidental Petroleum Corporation Supplemental Retirement Plan, “Beneficiary” means the person or persons so designated under Appendix A of the Occidental Petroleum Corporation Supplemental Retirement Plan.

Notwithstanding the foregoing, where an Employee becomes a Participant through merger of another plan into this Plan, “Beneficiary” means the person or persons so designated under such plan until a new Beneficiary designation is effected under the Retirement Plan by such Employee.

2. Section 2.1(l), relating to the definition of “Deferred Compensation Plan”, is amended in its entirety to read as follows:

(l)

Deferred Compensation Plan” means the Occidental Petroleum Corporation 2005 Deferred Compensation Plan, as amended from time to time. Effective October 12, 2006, “Deferred Compensation Plan” means the Occidental Petroleum Corporation Modified Deferred Compensation Plan, as amended from time to time.

3. Effective January 1, 2007, a new subsection (bb), defining “Annual Bonus Paid”, is added to the end of Section 2.1 to read as follows:

(bb)

“Annual Bonus Paid” means up to the first $100,000 of bonus paid to a Participant, who is not a “named executive officer”, as that term is defined in Regulations S-K under the Securities Exchange Act of 1934 (17 CFR §229.402(a)(3)), during the Plan Year under a regular annual incentive compensation plan, such as the Company's Variable Compensation Program or Incentive Compensation Program (but excluding without limitation a special individual or group bonus, a project bonus, and any other special bonus.

4. Effective January 1, 2007, a new subsection (cc), defining “DCP Eligible Bonus”, is added to the end of Section 2.1 to read as follows:

(cc)	“DCP Eligible Bonus” means the amount of bonus a Participant receives and is entitled to defer under the Deferred Compensation Plan without regard to the annual deferral limit of $75,000 or the Deferred Compensation Plan balance limit of $1 million, as described in the Deferred Compensation Plan.

5. Section 4.2, relating to Allocations Relating to the Savings Plan, is amended in its entirety to read as follows:

4.2	Allocations Relating to the Savings Plan
(a)	Eligibility. Effective January 1, 2007, an Employee who is eligible to participate in the Savings Plan for the Plan Year and whose Base Pay Paid plus Annual Bonus Paid for the Plan Year exceeds the amount specified in Code section 401(a)(17) as adjusted and in effect for the Plan Year shall be provided the allocation for the Plan Year specified in subsection (b).
(b)	Allocation Amount. The amount to be allocated as of the last day of the Plan Year under this Plan with respect to a Participant described in subsection (a) above for the Plan Year shall equal the sum of:

(1)	6 percent of the Employee’s Base Pay Paid plus Annual Bonus Paid in excess of the amount specified in Code section 401(a)(17) as adjusted and in effect for the Plan Year; and
(2)	5 percent of the amount allocated under paragraph (1) which shall be allocated to the account maintained for the Participant in lieu of interest on such amount for the Plan Year.

6. Section 4.1(b)(2)(B)(i), relating to Allocations to the Retirement Plan, is amended in its entirety to read as follows:

(i)	Effective January 1, 2007, Actual Pretax Deferrals and After-Tax Contributions, as those terms are defined under the Savings Plan, made to the Savings Plan for the Plan Year, and

7. Section 4.1(b)(2)(B)(ii), relating to Allocations to the Retirement Plan, is amended in its entirety to read as follows:

(ii)	Effective January 1, 2007, Actual Matching Contributions, as that term is defined under the Savings Plan, made to the Savings Plan for the Plan Year.

8. Section 4.3, relating to Allocations Relating to the Deferred Compensation Plan, amended in its entirety to read as follows:

4.3

Allocations Relating to the Deferred Compensation Plan

(a)	Retirement Plan

(1)	Eligibility. An Employee who is a participant in the Retirement Plan and eligible to participate in the Deferred Compensation Plan for the Plan Year shall be provided the allocation for the Plan Year specified in subsection 4.3(a)(2).
(2)	Allocation Amount. Effective January 1, 2007, the amount to be allocated in a Plan Year under this Plan with respect to a Participant described in subsection 4.3(a)(1) above for the Plan Year shall equal that Participant’s applicable percentage multiplied by the amount of the DCP Eligible Bonus the Participant receives. This allocation shall be made irrespective of whether such Participant elects to defer under the Deferred Compensation Plan all or any part of any bonus to which he might be entitled. Notwithstanding the preceding sentence, no allocation shall be made to the account of a Participant who is not an Employee on the date that any such bonus is awarded.
	For purposes of this subsection, the term “applicable percentage” shall mean 12 percent in the case of a Participant who shall have attained age 35 prior to the end of the Plan Year in which the allocation is made and 8 percent in the case of a Participant who shall not have attained age 35 prior to the end of the Plan Year in which the allocation is made. The allocation described in this section shall be made to the account of each Participant effective as of the date on which the Participant is awarded the bonus he is entitled to defer under the Deferred Compensation Plan.

(b)	Savings Plan

(1)	Eligibility. An Employee who is a participant in the Savings Plan and eligible to participate in the Deferred Compensation Plan for the Plan Year shall be provided the allocation for the Plan Year specified in subsection 4.3(b)(2), unless such an allocation has been made under the Deferred Compensation Plan, in which case, no allocation shall be made under this subsection 4.3(b).
(2)	Allocation Amount. Effective January 1, 2007, the amount to be allocated in a Plan Year under this Plan with respect to a Participant described in subsection 4.3(b)(1) above for the Plan Year shall equal that Participant’s applicable percentage multiplied by the amount of the Annual Bonus Paid the Participant receives. This allocation shall be made irrespective of whether such Participant elects to defer under the Deferred Compensation Plan all or any part of any bonus to which he might be entitled. Notwithstanding the preceding sentence, no allocation shall be made to the account of a Participant who is not an Employee on the date that any such bonus is awarded.
	For purposes of this subsection, the term “applicable percentage” shall mean the sum of the Pretax Deferral and After-Tax Contribution rates elected by the Participant under the Savings Plan (or any successor provision), up to 6 percent. The allocation described in this section shall be made to the account of each Participant effective as of the date on which the Participant is awarded the bonus he is entitled to defer under the Deferred Compensation Plan.

9. Section 5.2(b)(2), relating to Annual Installment Payments under “Available Times and Forms of Payment,” is amended in its entirety to read as follows:

(2)

Annual installment payments over 5, 10, 15, or 20 years, as elected by the Participant, commencing during the first calendar quarter following the calendar year in which occurs the distribution event specified in section 5.1, except death, and continuing each year thereafter until the final installment is paid or, if earlier, the Participant dies. For purposes of section 5.3 below, the installment payments are to be treated as a series of separate payments. While benefits are to be paid in installments, the Participant’s account will continue to be adjusted as provided in section 4.4(a) until the series of installments has been completed. The amount of each annual installment while the Participant is alive shall equal the amount credited to the account as of January 31 of the year in which the installment is to be paid, multiplied by a fraction, the numerator of which is 1, and the denominator of which is the number of installments (including the current one) which remain to be paid. Each installment shall be paid as soon as administratively possible after January 31

of the calendar year. If the Participant dies while installments remain to be paid, the remaining account credited to the Participant shall be paid to the Beneficiary as soon as practicable following the Participant’s death.

10. Exhibit A to the SRPII is amended in its entirety to read as follows:

EXHIBIT A

Participants with pre-October 4, 2004 Retainer Agreements

Axelson, Jr., C.J.

Doucet, M.J.

Freund, M.C.

Hull Jr., C.W.

Hurst III, J.L.

Leach, A.R.

Lorraine, R.A.

Oenbring, P.R.

Vincent, P.G.

Watkins, A.A.

10. Except as amended above, the terms of the Plan as in effect prior to this amendment shall continue unchanged.

* * * * *

Occidental Petroleum Corporation

Pension and Retirement Plan

Administrative Committee

Richard W. Hallock

Samuel P. Dominick, Jr.

Jim A. Leonard

James M. Lienert

Robert E. Sawyer

Darin S. Moss

Exhibit 10.23

EXHIBIT 10.23

AMENDMENT NUMBER 3

TO THE

OCCIDENTAL PETROLEUM CORPORATION

SUPPLEMENTAL RETIREMENT PLAN II

Effective as of January 1, 2005

The Occidental Petroleum Corporation Supplemental Retirement Plan II (Effective as of January 1, 2005) (“Plan”) is hereby amended effective as of January 1, 2008 (unless a different effective date is specified) as follows:

1.	Section 2.1(d), relating to the definition of “Base Pay of Record,” is amended in its entirety to read as follows:

(d)	“Base Pay of Record” means the base salary and wages earned while a Participant from an Employer for services rendered, including pretax deferrals under the Savings Plan, and amounts contributed pursuant to the Occidental Petroleum Flexible Spending Accounts Plan, as amended from time to time.

(1)	Base Pay of Record does not include:

(A)	Bonuses, incentives, overtime, shift differential, and overseas differentials;
(B)	Reimbursement for expenses or allowances, including automobile allowances and moving allowances;
(C)	Any amount contributed by the Employer (other than pretax deferrals under the Savings Plan and any amounts contributed pursuant to the Occidental Petroleum Flexible Spending Accounts Plan, as amended from time to time) to any qualified plan or plan of deferred compensation; and
(D)	Any amount paid by an Employer for other fringe benefits, such as health and hospitalization, and group life insurance benefits, or perquisites.

(2)	Base Pay of Record is determined in accordance with the following rules:

(A)	For Participants compensated by salary, Base Pay of Record means the actual base salary of record for the Participant (subject to the exclusions listed above).
(B)	For Participants compensated based on mileage driven (primarily truck drivers), Base Pay of Record means the number of miles driven multiplied by the applicable mileage pay rate (subject to the exclusions listed above), plus the Participant’s scheduled number of hours worked in the pay period multiplied by the Participant’s base hourly rate (subject to the exclusions listed above).

(C)	For Participants compensated at an hourly rate, Base Pay of Record means the base hourly rate (subject to the exclusions listed above) multiplied by the number of regularly scheduled hours worked in a pay period. If the Active Participant’s regularly scheduled work week is more than 40 hours, Base Pay of Record shall include an additional amount equal to the base hourly rate (subject to the exclusions listed above) times one half the number of regularly scheduled hours worked in excess of 40 in the work week.
(D)	For Participants compensated on an eight, ten, twelve, or some other assigned hour Shift Basis and whose annual compensation is pre-determined under the Company’s payroll recordkeeping system, Base Pay of Record for each pay period shall be the Participant’s pre-determined annual compensation (subject to the exclusions listed above) divided by the number of pay periods applicable to the Participant during the Plan Year. For the purpose of this subsection, the term “Shift Basis” means any arrangement whereby Participants work the assigned hour daily shifts which may result in alternating work weeks of more and less than 40 hours per week.
(E)	Base Pay of Record includes vacation pay received in periodic payments and annual vacation payments made to Employees paid by commission, but does not include single sum vacation payments to active or terminating Employees.
(F)	Base Pay of Record includes base salary or wages received during paid leaves of absence and periodic notice pay, but, effective July 1, 2006, Base Pay of Record does not include single sum notice pay payments or any severance pay payments.
(G)	Base Pay of Record does not include long-term disability payments or payments made to any Participant pursuant to the Occidental Chemical Corporation Weekly Sickness and Accident Plan unless:

(i)	Such payments are made to the Participant through the payroll accounting department of the Company or an Affiliate, and
(ii)	The Participant is ineligible for participation in the Retirement Plan.

2.	Paragraph (1) of section 2.1(z), relating to the definition of “Threshold Amount,” is amended in its entirety to read as follows:

(1)	For the period between January 1, 2005 and December 31, 2006, the Plan Limit for the Plan Year, determined under Appendix II of the Savings Plan (or any successor provision), and, effective January 1, 2007, the Contribution Percentage Limit for the Plan Year, determined under Appendix E of the

Savings Plan (or any successor provision), for a highly compensated employee as defined under Code section 414(q), times the annualized Base Pay of Record;

3.	A new sentence is added at the end of section 3.1, relating to Effective Date of Participation, to read as follows:

Further, notwithstanding anything contrary contained herein, any Employee who participates or is eligible to participate in the THUMS Long Beach Company Savings and Investment Plan or the THUMS Long Beach Company Pension Plan beginning on or after January 1, 2008 through December 31, 2008 shall be ineligible to be a Participant.

4.	Paragraph (2) of section 4.1(b), relating to the Reduction Amount in determining Allocations to the Retirement Plan is amended in its entirety to read as follows:

(2)

Reduction Amount. The amounts contingently credited to the account maintained for the Participant during the Plan Year under paragraph (1) shall be reduced as of the last day of the Plan Year, but not below zero, by the amount determined under this paragraph. The reduction amount is intended to be equal to the Employee’s allocation under the Retirement Plan for the Plan Year assuming that the Employee maximized deferrals under the Savings Plan. After the reduction described in this paragraph, the remaining amount shall be permanently credited to the account maintained for the Participant.

(A)	No reduction shall apply to the account maintained for any Participant, including an LTD Participant, who is not an Employee on the last day of the Plan Year.
(B)	The reduction amount for other Participants shall be equal to the dollar limit in effect for the Plan Year under Code section 415(c)(1)(A) minus sum of the following:

(i)	For the period between January 1, 2005 and December 31, 2006,

(I)	the Plan Limit for the Plan Year, determined under Appendix II of the Savings Plan (or any successor provision), times the Participant’s Base Pay Paid, and
(II)	6 percent times the Participant’s Base Pay Paid for the Plan Year;

(ii)	Effective beginning on or after January 1, 2007,

(I)	the Contribution Percentage Limit for the Plan Year, determined under Appendix E of the Savings Plan (or any successor provision) times the Participant’s Base Pay Paid and 6 percent of the Annual Bonus for the Plan Year, and

(II)	6 percent times the sum of the Participant’s Base Pay Paid and Annual Bonus for the Plan Year.

For purposes of determining the reduction under this subparagraph, no portion of the sum of the Participant’s Base Pay Paid and Annual Bonus for the Plan Year in excess of the amount specified in Code section 401(a)(17) in effect for the Plan Year shall be taken into account. The reduction amount shall not be less than zero.

5.	Except as amended above, the terms of the Plan as in effect prior to this amendment shall continue unchanged.

* * * * *

Occidental Petroleum Corporation

Pension and Retirement Plan

Administrative Committee

Richard W. Hallock

Jim A. Leonard

James M. Lienert

Daniel S. Watts

Exhibit 12

EXHIBIT 12

OCCIDENTAL PETROLEUM CORPORATION AND SUBSIDIARIES

COMPUTATION OF TOTAL ENTERPRISE RATIOS OF EARNINGS TO FIXED CHARGES

(Amounts in millions, except ratios)

For the years ended December 31,	2007			2006			2005			2004			2003
Income from continuing operations	$	5,078		$	4,202		$	4,838		$	2,197		$	1,410
Add:
Minority interest ^(a)		75			111			74			76			62
Adjusted income from equity investments ^(b)		(28	)		(52	)		(53	)		(5	)		72
		5,125			4,261			4,859			2,268			1,544
Add:
Provision for taxes on income (other than
foreign oil and gas taxes)		1,577			1,545			632			891			593
Interest and debt expense ^(c)		344			297			305			270			337
Portion of lease rentals representative of the interest factor		60			52			47			40			8
		1,981			1,894			984			1,201			938
Earnings before fixed charges	$	7,106		$	6,155		$	5,843		$	3,469		$	2,482
Fixed charges:
Interest and debt expense including capitalized interest ^(c)	$	403		$	352		$	331		$	285		$	343
Portion of lease rentals representative of the interest factor		60			52			47			40			8
Total fixed charges	$	463		$	404		$	378		$	325		$	351
Ratio of earnings to fixed charges		15.35			15.24			15.46			10.67			7.07

(a)	Represents minority interests in net income of majority-owned subsidiaries and partnerships having fixed charges.
(b)	Represents income from less-than-50-percent-owned equity investments adjusted to reflect only dividends received.
(c)	Includes proportionate share of interest and debt expense of less-than-50-percent-owned equity investments. The 2007 amount includes a pre-tax charge of $167 million for the redemption and partial repurchase of various debt issues.

Exhibit 21

EXHIBIT 21

LIST OF SUBSIDIARIES

The following is a list of the Registrant’s subsidiaries at December 31, 2007, other than certain subsidiaries that did not in the aggregate constitute a significant subsidiary.

Name		Jurisdiction of Formation
Centurion Pipeline GP, Inc.		Delaware
Centurion Pipeline LP, Inc.		Delaware
Centurion Pipeline L.P.		Delaware
D. S. Ventures, Inc.		Texas
Glenn Springs Holdings, Inc.		Delaware
INDSPEC Chemical Corporation		Delaware
INDSPEC Holding Corporation		Delaware
INDSPEC Technologies, Ltd.		Pennsylvania
Ingleside Cogeneration GP, Inc.		Delaware
Ingleside Cogeneration GP 2, Inc.		Delaware
Ingleside Cogeneration Limited Partnership		Delaware
Laguna Petroleum Corporation		Texas
NGL Ventures LLC		Delaware
Occidental Andina, LLC		Delaware
Occidental Argentina Exploration and Production, Inc.		Cayman Islands
Occidental (Bermuda) Ltd.		Bermuda
Occidental Chemical Chile Limitada		Chile
Occidental Chemical Corporation		New York
Occidental Chemical Holding Corporation		California
Occidental Chemical Nevis, Inc.		Nevis
Occidental Chile Investments, LLC		Delaware
Occidental Crude Sales, Inc. (International)		Delaware
Occidental de Colombia, Inc.		Delaware
Occidental del Ecuador, Inc.		Nevis
Occidental Dolphin Holdings Ltd.		Bermuda
Occidental Energy Marketing, Inc.		Delaware
Occidental International Exploration and Production Company		California
Occidental International Holdings Ltd.		Bermuda
Occidental International (Libya), Inc.		Delaware
Occidental International Oil and Gas Ltd.		Bermuda
Occidental Latin America Holdings, Inc.		Delaware
Occidental Mukhaizna, LLC		Delaware
Occidental of Elk Hills, Inc.		Delaware
Occidental of Oman, Inc.		Nevis
Occidental of Yemen (Block S-1), Inc.		Cayman Islands
Occidental Oil and Gas Holding Corporation		California
Occidental OOOI Holder, Inc.		Delaware
Occidental Overseas Operations, Inc.		Delaware
Occidental Peninsula, LLC		Delaware
Occidental Peninsula II, Inc.		Nevis
Occidental Permian Ltd.		Texas
Occidental Permian Manager LLC		Delaware
Occidental Petroleum Investment Co.		California
Occidental Petroleum of Qatar Ltd.		Bermuda
Occidental Power Services, Inc.		Delaware

EXHIBIT 21 (cont’d.)

Name		Jurisdiction of Formation
Occidental PVC LP, Inc.		Delaware
Occidental Qatar Energy Company LLC		Delaware
Occidental Quimica do Brasil Ltda.		Brazil
Occidental Resources Company		Cayman Islands
Occidental Transportation Holding Corporation		Delaware
Occidental VCM LLC		Delaware
Occidental VCM LP, Inc.		Delaware
Occidental Yemen Ltd.		Bermuda
OOG Partner Inc.		Delaware
OOOI Chemical International, LLC		Delaware
OOOI Chemical Management, Inc.		Delaware
OOOI Chile Holder, Inc.		Nevis
OOOI Oil and Gas Management, Inc.		Delaware
OOOI Oil and Gas Sub, LLC		Delaware
OXYMAR		Texas
Oxy CH Corporation		California
Oxy Chemical Corporation		California
OXY Dolphin E&P, LLC		Nevis
Oxy Cogeneration Holding Company, Inc.		Delaware
OXY Dolphin Pipeline, LLC		Nevis
Oxy Energy Canada, Inc.		Delaware
Oxy Energy Services, Inc.		Delaware
Oxy Libya E&P Area 106 Ltd.		Bermuda
Oxy Libya E&P Area 124 Ltd.		Bermuda
Oxy Libya E&P Area 163 Ltd.		Bermuda
OXY Long Beach, Inc.		Delaware
OXY Oil Partners, Inc.		Delaware
OXY PBLP Holder, Inc.		Delaware
OXY PBLP Manager, LLC		Delaware
Oxy Pipeline I Company		Delaware
OXY USA Inc.		Delaware
OXY USA WTP LP		Delaware
OXY VCM, LP		Delaware
Oxy Vinyls Canada Inc.		Canada
Oxy Vinyls, LP		Delaware
OXY VPP Investments, Inc.		Delaware
Oxy Westwood Corporation		California
Permian Basin Limited Partnership		Delaware
Permian VPP Holder, LP		Delaware
Permian VPP Manager, LLC		Delaware
Repsol Occidental Corporation		Delaware
Stockdale Oil and Gas, Inc.		California
Vintage Petroleum, LLC		Delaware
Vintage Petroleum Boliviana, Ltd.		Bermuda
Vintage Production California LLC		Delaware
Vintage Petroleum International, Inc.		Oklahoma
Vintage Petroleum International Holdings, Inc.		Delaware
Vintage Petroleum South America Holdings, Inc.		Cayman Islands

Exhibit 23.1

EXHIBIT 23.1

Consent of Independent Registered Public Accounting Firm

To the Board of Directors

Occidental Petroleum Corporation:

We consent to the incorporation by reference in the registration statements (Nos. 333-142705, 333-123324, 33-14662, 33-47636, 33-64719, 333-49207, 333-72719, 333-78031, 333-37970, 333-55404, 333-63444, 333-82246, 333-83124, 333-96951, 333-104827, 333-115099 and 333-124732) on Forms S-3 and S-8 of Occidental Petroleum Corporation of our reports dated February 22, 2008, with respect to the consolidated balance sheets of Occidental Petroleum Corporation as of December 31, 2007 and 2006, 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, 2007 and the related financial statement schedule, and the effectiveness of internal control over financial reporting as of December 31, 2007, which reports appear in the December 31, 2007 annual report on Form 10-K of Occidental Petroleum Corporation. Our report on the financial statements of Occidental Petroleum Corporation refers to (i) a change in the method of accounting for uncertain tax positions, (ii) a change in the method of accounting for defined benefit pension and other postretirement plans, and (iii) a change in the method of accounting for share-based payments.

/s/ KPMG LLP

Los Angeles, California

February 22, 2008

Exhibit 23.2

EXHIBIT 23.2

EXPERT CONSENT

To the Board of Directors

Occidental Petroleum Corporation:

We consent to the inclusion in the Occidental Petroleum Corporation (Occidental) Form 10-K for the year ended December 31, 2007, and the incorporation by reference in Occidental’s registration statements (Nos. 333-123324, 33-14662, 33-47636, 33-64719, 333-49207, 333-72719, 333-78031, 333-37970, 333-55404, 333-63444, 333-82246, 333-83124, 333-96951, 333-104827, 333-115099, 333-124732 and 333-142705), of references to our name and to our letter dated February 4, 2008, relating to our review of the procedures and methods used by Occidental in its oil and gas proved reserves estimation process.

/s/ RYDER SCOTT COMPANY, L.P.

Houston, Texas

February 8, 2008

Exhibit 31.1

EXHIBIT 31.1

RULE 13a – 14(a) / 15d – 14 (a)

CERTIFICATION

PURSUANT TO §302 OF THE SARBANES-OXLEY ACT OF 2002

I, Ray R. Irani, certify that:

1. I have reviewed this annual report on Form 10-K of Occidental Petroleum Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: February 22, 2008

/s/ RAY R. IRANI

Ray R. Irani

Chairman of the Board of Directors and

Chief Executive Officer

Exhibit 31.2

EXHIBIT 31.2

RULE 13a – 14(a) / 15d – 14 (a)

CERTIFICATION

PURSUANT TO §302 OF THE SARBANES-OXLEY ACT OF 2002

I, Stephen I. Chazen, certify that:

1. I have reviewed this annual report on Form 10-K of Occidental Petroleum Corporation;

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: February 22, 2008

/s/ STEPHEN I. CHAZEN

Stephen I. Chazen

President and Chief Financial Officer

Exhibit 32.1

EXHIBIT 32.1

CERTIFICATION OF CEO AND CFO PURSUANT TO

18 U.S.C. § 1350,

AS ADOPTED PURSUANT TO

§ 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report on Form 10-K of Occidental Petroleum Corporation (the “Company”) for the fiscal period ended December 31, 2007, as filed with the Securities and Exchange Commission on February 22, 2008 (the “Report”), Ray R. Irani, as Chief Executive Officer of the Company, and Stephen I. Chazen, as Chief Financial Officer of the Company, each hereby certifies, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that, to the best of his knowledge:

(1)	The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2)	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ RAY R. IRANI

Name:	Ray R. Irani
Title:	Chairman of the Board of Directors and Chief Executive Officer
Date:	February 22, 2008

/s/ STEPHEN I. CHAZEN

Name:	Stephen I. Chazen
Title:	President and Chief Financial Officer
Date:	February 22, 2008

A signed original of this written statement required by Section 906 has been provided to Occidental Petroleum Corporation and will be retained by Occidental Petroleum Corporation and furnished to the Securities and Exchange Commission or its staff upon request.

This certification accompanies the Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and shall not, except to the extent required by the Sarbanes-Oxley Act of 2002, be deemed filed by the Company for purposes of Section 18 of the Securities Exchange Act of 1934, as amended.