10-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

RAnnual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934	¨ Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the fiscal year ended December 31, 2012	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
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

Indicatebycheckmarkiftheregistrantisawell-knownseasonedissuer,asdefinedinRule405oftheSecuritiesAct. Yes R 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).      Yes £   No  R

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.     Yes R   No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate web site, if any, every Interactive Date File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or such shorter period as the registrant was required to submit and post files).      Yes R   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.   R

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company.  (See definition of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act).

Large Accelerated Filer	R	Accelerated Filer	£
Non-Accelerated Filer	£	Smaller Reporting Company	£

Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2) Yes £   No  R

The aggregate market value of the voting common stock held by nonaffiliates of the registrant was approximately $68.1 billion, computed by reference to the closing price on the New York Stock Exchange composite tape of $85.77 per share of Common Stock on June 30, 2012.  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, 2013, there were 805,515,153 shares of Common Stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s definitive Proxy Statement, relating to its May 3, 2013 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
	Midstream, Marketing and Other Operations....................................................................................................................	5
	Capital Expenditures.........................................................................................................................................................	5
	Employees.........................................................................................................................................................................	5
	Environmental Regulation.................................................................................................................................................	5
	Available Information.........................................................................................................................................................	5
Item 1A	Risk Factors............................................................................................................................................................................	6
Item 1B	Unresolved Staff Comments...................................................................................................................................................	7
Item 3	Legal Proceedings..................................................................................................................................................................	7
Item 4	Mine Safety Disclosures........................................................................................................................................................	7
	Executive Officers...................................................................................................................................................................	8
Part II
Item 5	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities...............	8
Item 6	Selected Financial Data..........................................................................................................................................................	11
Item 7 and 7A	Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A).....................................	11
	Strategy.............................................................................................................................................................................	12
	Oil and Gas Segment........................................................................................................................................................	13
	Chemical Segment............................................................................................................................................................	19
	Midstream, Marketing and Other Segment........................................................................................................................	20
	Segment Results of Operations.........................................................................................................................................	21
	Significant Items Affecting Earnings..................................................................................................................................	24
	Taxes.................................................................................................................................................................................	24
	Consolidated Results of Operations..................................................................................................................................	24
	Consolidated Analysis of Financial Position......................................................................................................................	25
	Liquidity and Capital Resources........................................................................................................................................	26
	Off-Balance-Sheet Arrangements......................................................................................................................................	28
	Contractual Obligations.....................................................................................................................................................	28
	Lawsuits, Claims and Contingencies.................................................................................................................................	29
	Environmental Liabilities and Expenditures.......................................................................................................................	29
	Foreign Investments..........................................................................................................................................................	30
	Critical Accounting Policies and Estimates........................................................................................................................	30
	Significant Accounting and Disclosure Changes...............................................................................................................	34
	Derivative Activities and Market Risk.................................................................................................................................	34
	Safe Harbor Discussion Regarding Outlook and Other Forward-Looking Data................................................................	36
Item 8	Financial Statements and Supplementary Data......................................................................................................................	37
	Management's Annual Assessment of and Report on Internal Control Over Financial Reporting.....................................	37
	Report of Independent Registered Public Accounting Firm on Consolidated Financial Statements.................................	38
	Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting.......................	39
	Consolidated Balance Sheets...........................................................................................................................................	40
	Consolidated Statements of Income..................................................................................................................................	42
	Consolidated Statements of Comprehensive Income.......................................................................................................	43
	Consolidated Statements of Stockholders' Equity.............................................................................................................	43
	Consolidated Statements of Cash Flows...........................................................................................................................	44
	Notes to Consolidated Financial Statements.....................................................................................................................	45
	Quarterly Financial Data (Unaudited)................................................................................................................................	73
	Supplemental Oil and Gas Information (Unaudited)..........................................................................................................	75
	Financial Statement Schedule:
	Schedule II – Valuation and Qualifying Accounts..............................................................................................................	87
Item 9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure..................................................	88
Item 9A	Controls and Procedures........................................................................................................................................................	88
	Disclosure Controls and Procedures.................................................................................................................................	88
Item 9B	Other Information....................................................................................................................................................................	88
Part III
Item 10	Directors, Executive Officers and Corporate Governance......................................................................................................	88
Item 11	Executive Compensation........................................................................................................................................................	88
Item 12	Security Ownership of Certain Beneficial Owners and Management.....................................................................................	89
Item 13	Certain Relationships and Related Transactions and Director Independence........................................................................	89
Item 14	Principal Accountant Fees and Services.................................................................................................................................	89
Part IV
Item 15	Exhibits and Financial Statement Schedules..........................................................................................................................	89

Part I

ITEMS 1 AND 2 BUSINESS AND PROPERTIES

In this report, "Occidental" means Occidental Petroleum Corporation, a Delaware corporation (OPC), or OPC and one or more entities in which it owns a controlling interest (subsidiaries).  Occidental conducts its operations through various 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 three segments. The oil and gas segment explores for, develops and produces oil and condensate, natural gas liquids (NGLs) and natural gas. The chemical segment (OxyChem) mainly manufactures and markets basic chemicals and vinyls. The midstream, marketing and other segment (midstream and marketing) gathers, processes, transports, stores, purchases and markets oil, condensate, NGLs, natural gas, carbon dioxide (CO₂) and power. It also trades around its assets, including transportation and storage capacity, and trades oil, NGLs, gas and other commodities. The segment also invests in entities that conduct similar activities.

For information regarding Occidental's current developments, segments and geographic areas, see the information in the "Management’s Discussion and Analysis of Financial Condition and Results of Operations" (MD&A) section of this report and Note 16 to the Consolidated Financial Statements.

OIL AND GAS OPERATIONS

General

Occidental’s domestic oil and gas operations are located mainly in California, Colorado, Kansas, New Mexico, North Dakota, Oklahoma, Texas and West Virginia. International operations are located in Bahrain, Bolivia, Colombia, Iraq, Libya, Oman, Qatar, the United Arab Emirates (UAE) and Yemen.  

ProvedReservesandSalesVolumes

The table below shows Occidental’s total oil, NGLs and natural gas proved reserves and sales volumes in 2012, 2011 and 2010. See "MD&A — Oil and Gas Segment," and the information under the caption "Supplemental Oil and Gas Information" for certain details regarding Occidental’s proved reserves, the reserves estimation process, sales and production volumes, production costs and other reserves-related data.

Comparative Oil and Gas Proved Reserves and Sales Volumes

Oil, which includes condensate, and NGLs in millions of barrels; natural gas in billions of cubic feet (Bcf); barrels of oil equivalent (BOE) in millions.

	2012					2011					2010
Proved Reserves	Oil	NGLs	Gas	BOE	(a)	Oil	NGLs	Gas	BOE	(a)	Oil	NGLs	Gas	BOE	(a)
United States	1,567	216	2,889	2,265		1,526	225	3,365	2,313		1,460	237	3,034	2,203
International (b,c)	469	116	2,679	1,031		482	55	1,958	863		552	61	2,104	964
Total	2,036	332	5,568	3,296	(d)	2,008	280	5,323	3,176	(d)	2,012	298	5,138	3,167	(d)
Sales Volumes
United States	93	27	300	170		84	25	285	156		80	19	247	140
International (b,c)	78	3	170	110		80	4	162	111		83	5	172	117
Total	171	30	470	280		164	29	447	267		163	24	419	257

Note: The detailed proved reserves information presented in accordance with Item 1202(a)(2) to Regulation S-K under the Securities Exchange Act of 1934 (Exchange Act) is provided on pages 75-78.

(a) Natural gas volumes have been converted to BOE based on energy content of six thousand cubic feet (Mcf) of gas to one barrel of oil.  Barrels of oil equivalence does not necessarily result in price equivalence.  The price of natural gas on a barrel of oil equivalent basis is currently substantially lower than the corresponding price for oil and has been similarly lower over the recent past. For example, in 2012, the average prices of West Texas Intermediate (WTI) oil and New York Mercantile Exchange (NYMEX) natural gas were $94.21 per barrel and $2.81 per Mcf, respectively, resulting in an oil to gas ratio of over 30.

(b) Excludes volumes from the Argentine operations sold in February 2011 and classified as discontinued operations.

(c) Reserves exclude the former noncontrolling interest in a Colombian subsidiary because, on December 31, 2010, Occidental restructured its Colombian operations to take a direct working interest in the related assets. The 2010 sales volumes include the noncontrolling interest in the Colombian subsidiary, while the 2012 and 2011 sales volumes exclude such amounts.

(d) Stated on a net basis after applicable royalties.  Includes proved reserves related to production-sharing contracts (PSCs) and other similar economic arrangements of 0.9 billion BOE in 2012, 1.0 billion BOE in 2011 and 1.1 billion BOE in 2010.

3

Competition

As a producer of oil and condensate, NGLs and natural gas, Occidental competes with numerous other domestic and foreign private and government producers. Oil, NGLs and natural gas are commodities that are sensitive to prevailing global and, in certain cases local, current and anticipated market conditions. They are sold at current market prices or on a forward basis to refiners and other market participants. Occidental’s competitive strategy relies on increasing production through developing conventional and unconventional mature and underdeveloped fields, enhanced oil recovery (EOR) projects and strategic acquisitions. Occidental also competes to develop and produce its worldwide oil and gas reserves cost-effectively and obtain qualified labor and services.

CHEMICAL OPERATIONS

General

OxyChem owns and operates manufacturing plants at 22 domestic sites in Alabama, Georgia, Illinois, Kansas, Louisiana, Michigan, New Jersey, New York, Ohio, Pennsylvania and Texas and at two international sites in Canada and Chile. It also has an interest in a Brazilian joint venture.

Competition

OxyChem competes with numerous other domestic and foreign chemical producers. For every product it manufactures and markets, OxyChem’s market position was first or second in the United States and first, second or third in the world in 2012. OxyChem’s competitive strategy is to be a low-cost producer of its products in order to compete on price.

OxyChem produces the following products:

Principal Products	Major Uses	Annual Capacity
Basic Chemicals
Chlorine	Raw material for ethylene dichloride (EDC), water treatment and pharmaceuticals	4.0 million tons (a)
Caustic soda	Pulp, paper and aluminum production	4.2 million tons (a)
Chlorinated organics	Refrigerants, silicones and pharmaceuticals	0.9 billion pounds
Potassium chemicals	Fertilizers, batteries, soaps, detergents and specialty glass	0.4 million tons
EDC	Raw material for vinyl chloride monomer (VCM)	2.4 billion pounds (a)
Chlorinated isocyanurates	Swimming pool sanitation and disinfecting products	131 million pounds
Sodium silicates	Catalysts, soaps, detergents and paint pigments	0.6 million tons
Calcium chloride	Ice melting, dust control, road stabilization and oil field services	0.7 million tons
Vinyls
VCM	Precursor for polyvinyl chloride (PVC)	6.2 billion pounds
PVC	Piping, building materials, and automotive and medical products	3.7 billion pounds
Other Chemicals
Resorcinol	Tire manufacture, wood adhesives and flame retardant synergist	50 million pounds

(a) Includes gross capacity of a joint venture in Brazil, owned 50 percent by Occidental.

4

MIDSTREAM AND MARKETING OPERATIONS

The midstream and marketing operations are conducted in the locations described below:

Location	Description	Capacity
Gas Plants
California, Texas, New Mexico and Colorado	Occidental- and third-party-operated natural gas gathering, compression and processing systems, and CO2 processing	3.1 billion cubic feet per day
Pipelines
Texas, New Mexico and Oklahoma	Common carrier oil pipeline and storage system	365,000 barrels of oil per day 5.8 million barrels of oil storage 2,700 miles of pipeline
Texas, New Mexico and Colorado	CO2 fields and pipeline systems transporting CO2 to oil and gas producing locations	2.4 billion cubic feet per day
Dolphin Pipeline - Qatar and United Arab Emirates	Equity investment in a natural gas pipeline	3.2 billion cubic feet of natural gas per day (a)
Western and Southern United States and Canada	Equity investment in entity involved in pipeline transportation, storage, terminalling and marketing of oil, gas and related petroleum products	18,800 miles of pipeline and gathering systems (b) Storage for 135 million barrels of oil and other petroleum products and 93 billion cubic feet of natural gas(b)
Marketing and Trading
Texas, Connecticut, United Kingdom, Singapore and other	Trades around its assets, including transportation and storage capacity, and purchases, markets and trades oil, NGLs, gas, power and other commodities	Not applicable
Power Generation
California, Texas and Louisiana	Occidental-operated power and steam generation facilities	1,800 megawatts per hour and 1.6 million pounds of steam per hour

(a) Pipeline currently transports 2.3 Bcf per day. Additional gas compression and customer contracts are required to reach capacity.

(b) Amounts are gross, including interests held by third parties.

CAPITAL EXPENDITURES

For information on capital expenditures, see the information under the heading "Liquidity and Capital Resources”in the MD&A section of this report.

EMPLOYEES

Occidental employed approximately 12,300 people at December 31, 2012, 8,700 of whom were located in the United States. Occidental employed approximately 8,000 people in the oil and gas and midstream and marketing segments and 3,000 people in the chemical segment. An additional 1,300 people were employedin administrative and headquarters functions. Approximately 800 U.S.-based employees and 700 foreign-based employees are represented by labor unions.

Occidental has a long-standing strict policy to provide fair and equal employment opportunities to all applicants and employees.

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 and "Risk Factors."

AVAILABLE INFORMATION

Occidental makes the following information available free of charge on its website 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 electronically filed with, or furnished to, 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.)

Information contained on Occidental's website is not part of this report.

5

ITEM 1A    RISK FACTORS

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

Occidental’s financial results correlate closely to the prices it obtains for its products, particularly oil and, to a lesser extent, natural gas and its chemical products.

Changes in consumption patterns, global and local economic conditions, inventory levels, production disruptions, the actions of OPEC, currency exchange rates, worldwide drilling and exploration activities, technological developments, weather, geophysical and technical limitations, transportation bottlenecks and other matters affect the supply and demand dynamics of oil and gas, which, along with the effect of changes in market perceptions, contribute to price unpredictability and volatility.

Demand and, consequently, the price obtained for Occidental’s chemical products correlate strongly to the health of the United States and global economies, as well as chemical industry expansion and contraction 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 results of operations and its ability to grow production and replace reserves.

Results of operations, reserve replacement and growth in oil and gas production depend, in part, on Occidental’s ability to profitably acquire, develop or find additional reserves. Occidental has many competitors (including national oil companies), some of which: (i) are larger and better funded, (ii) may be willing to accept greater risks or (iii) have special competencies. Competition for reserves may make it more difficult to find attractive investment opportunities or require delay of reserve replacement efforts. During periods of low product prices, any cash conservation efforts may delay production growth and reserve replacement efforts.

Occidental may experience delays, cost overruns, losses or unrealized expectations in development efforts and exploration activities.

Occidental bears the risks of development delays and cost overruns due to approval delays for drilling and other permits, equipment failures, construction delays, escalating costs or competition for services, materials, supplies or labor, property or border disputes, disappointing reservoir performance and other associated risks that may affect its ability to profitably grow production, replace reserves and achieve its targeted returns.

Exploration is inherently risky. Exploration is subject to delays, misinterpretation of geologic or engineering data, unexpected geologic conditions or finding reserves of disappointing quality or quantity, which may result in significant losses.

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 new or amended laws and regulations, or interpretations of such laws and regulations, including those related to drilling, manufacturing or production processes (including hydraulic fracturing), labor and employment, taxes, royalty rates, permitted production rates, entitlements, import, export and use of equipment, use of land, water and other natural resources, safety, security and environmental protection, all of which may increase Occidental’s costs or reduce the demand for its products; and

Ø refusal of, or delay in, the extension or grant of exploration, development or production 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, labor unrest, OPEC production restrictions, equipment import restrictions and sanctions. Exposure to such risks may increase if a greater percentage of Occidental’s future oil and gas production comes from foreign sources.

Occidental faces risks associated with its acquisitions and divestitures.

Occidental’s acquisition and divestiture activities carry risks that it may: (i) not fully realize anticipated benefits due to less-than-expected reserves or production or changed circumstances, such as the deterioration of natural gas prices over the last few years; (ii) bear unexpected integration costs or experience other integration difficulties; (iii) experience share price declines based on the market’s evaluation of the activity; or (iv) assume or retain liabilities that are greater than anticipated.

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

Reported oil and gas reserves are an estimate based on engineers' periodic review of reservoir characteristics and recoverability, including production decline rates, operating performance and economic feasibility at the prevailing commodity prices as well as capital and operating costs. If Occidental were required to make significant negative reserve revisions, its results of operations and stock price could be adversely affected.

6

Concerns about climate change may affect Occidental’s operations.

The U.S. federal government and the state of California have adopted, and other jurisdictions are considering, legislation, regulations or policies that seek to control or reduce the production, use or emissions of “greenhouse gases” (GHG), to control or reduce the production or consumption of fossil fuels, and to increase the use of renewable or alternative energy sources. For example, California’s cap-and-trade program currently applies to Occidental's operations in the state. The U.S. Environmental Protection Agency has begun to regulate certain GHG emissions from both stationary and mobile sources. The uncertain outcome and timing of existing and proposed international, national and state measures make it difficult to predict their business impact. However, Occidental could face risks of project execution, higher costs and taxes and lower demand for and restrictions on the use of its products as a result of ongoing GHG reduction efforts.

Occidental’s businesses may experience catastrophic events.

The occurrence of events, such as earthquakes, hurricanes, floods, well blowouts, fires, explosions, chemical releases, industrial accidents, physical attacks and other events that cause operations to cease or be curtailed, may negatively affect Occidental’s businesses and the communities in which it operates. Third-party insurance may not provide adequate coverage or Occidental may be self-insured with respect to the related losses.

Cyber attacks could significantly affect Occidental.

Cyber attacks on businesses have escalated in recent years. Occidental relies on electronic systems and networks to control and manage its oil and gas, chemicals, trading and pipeline operations and has multiple layers of security to mitigate risks of cyber attack. If, however, Occidental were to experience an attack and its security measures failed, the potential consequences to its businesses and the communities in which it operates could be significant. In 2009 and 2010, Occidental experienced a cyber attack on its email system, which had no effect on its operations, financial systems or reputation.

Other risk factors.

Additional discussion of risks and uncertainties related to price and demand, litigation, environmental matters, oil and gas reserves estimation processes, foreign operations, impairments, derivatives, market risks and internal controls appears under the headings: "MD&A — Oil & Gas Segment — Proved Reserves" and "— Industry Outlook," "— Chemical Segment — Industry Outlook," "— Midstream, Marketing and Other Segment — Industry Outlook," "— Consolidated Results of Operations," "— Lawsuits, Claims and Other Contingencies," "— Environmental Liabilities and Expenditures," "— Foreign Investments," "— Critical Accounting Policies and Estimates," "— Derivative Activities and Market Risk," and "Management's Annual Assessment of and Report on Internal Control Over Financial Reporting."

The risks described in this report are not the only risks facing Occidental and other risks, including risks deemed immaterial, may have material adverse effects.

ITEM 1B UNRESOLVED STAFF COMMENTS

Occidental has no unresolved SEC staff comments that have been outstanding more than 180 days at December 31, 2012.

ITEM 3    LEGAL PROCEEDINGS

A subsidiary of OPC reached a settlement in principle in January 2013 with the Louisiana Department of Environmental Quality regarding penalties associated with certain self-disclosed air emissions and permit deviations. Under the proposed settlement, the subsidiary will pay administrative penalties and an additional amount to fund air quality modeling as a supplemental environmental project.

The New Mexico Environment Department asserted a penalty claim on April 6, 2012, against an OPC subsidiary for alleged notification, permitting and emissions violations of the New Mexico Air Quality Control Act at a facility in Lea County, New Mexico. The subsidiary is evaluating this claim.

Although the matters described above are reportable events, their financial impact is expected to be insignificant.

For information regarding other legal proceedings, see the information under the caption, "Lawsuits, Claims and Other Contingencies" in the MD&A section of this report and in Note 9 to the Consolidated Financial Statements.

ITEM 4    MINE SAFETY DISCLOSURES

Not applicable.

7

EXECUTIVE OFFICERS

The current term of employment of each executive officer of Occidental will expire at the May 3, 2013, organizational meeting of the Board of Directors or when a successor is selected. The following table sets forth the executive officers of Occidental:

Name	Age at February 26, 2013	Positions with Occidental and Subsidiaries and Employment History
Stephen I. Chazen	66	Chief Executive Officer since 2011 and President since 2007; 2010-2011, Chief Operating Officer; 1999-2010, Chief Financial Officer; Director since 2010.
Dr. Ray R. Irani	78	Executive Chairman since 2011; 1990-2011, Chairman and Chief Executive Officer; Director since 1984.
Cynthia L. Walker	36	Executive Vice President and Chief Financial Officer since 2012; Goldman, Sachs & Co.: 2010-2012, Managing Director; 2005-2010, Vice President.
Donald P. de Brier	72	Corporate Executive Vice President and Corporate Secretary since 2012; 1993-2012, Executive Vice President, General Counsel and Secretary.
William E. Albrecht	61	Vice President since 2008; Occidental Oil and Gas Corporation (OOGC): President — Oxy Oil & Gas, Americas since 2011; OOGC: President — Oxy Oil & Gas, USA 2008-2011; 2007-2008, Vice President, California Operations.
Edward A. "Sandy" Lowe	61	Vice President since 2008; OOGC: President — Oxy Oil & Gas, International Production since 2009; 2008-2009, Executive Vice President — Oxy Oil & Gas, International Production and Engineering; 2008, Executive Vice President — Oxy Oil & Gas, Major Projects.
Willie C.W. Chiang	52	Executive Vice President, Operations since 2012; ConocoPhillips: 2011-2012, Senior Vice President, Refining, Marketing, Transportation and Commercial; 2008-2011, Senior Vice President, Refining, Marketing and Transportation.
James M. Lienert	60	Executive Vice President — Business Support since 2012; 2010-2012, Executive Vice President and Chief Financial Officer; 2006-2010, Executive Vice President — Finance and Planning.
John C. Ale	58	Vice President and General Counsel since 2012; Skadden, Arps, Slate, Meagher & Flom LLP: 2002-2012, Partner.
Roy Pineci	50	Vice President, Controller and Principal Accounting Officer since 2008; 2007-2008, Senior Vice President, Finance — Oil and Gas.
B. Chuck Anderson	53	Vice President since 2012; President of Occidental Chemical Corporation since 2006.

Part II

ITEM 5 MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER 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 approximately 32,200 stockholders of record at December 31, 2012, and by approximately 494,000 additional stockholders whose shares were held for them in street name or nominee accounts. The common stock is listed and traded 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.

The quarterly dividends declared on the common stock were $0.54 for each quarter of 2012 ($2.16 for the year). On February 14, 2013, a quarterly dividend of $0.64 per share was declared on the common stock, payable on April 15, 2013 to stockholders of record on March 8, 2013. The declaration of future 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.

8

SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS

All of Occidental's stock-based compensation plans for its employees and non-employee directors have been approved by the stockholders. The aggregate number of shares of Occidental common stock authorized for issuance under such plans is approximately 66 million, of which approximately 15 million had been issued through December 31, 2012. The following is a summary of the securities available for issuance under such 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))
3,502,857  (1)		31.88 (2)		19,251,258 (3)

(1) Includes shares reserved to be issued pursuant to stock options (Options), stock appreciation rights (SARs) and performance-based awards. Shares for performance-based awards are included assuming maximum payout, but may be paid out at lesser amounts, or not at all, according to achievement of performance goals.

(2) Price applies only to the Options and SARs included in column (a). Exercise price is not applicable to the other awards included in column (a).

(3) A plan provision requires each share covered by an award (other than Options and SARs) to be counted as if three shares were issued in determining the number of shares that otherwise would have been available for future awards. Accordingly, the number of shares available for future awards may be less than the amount shown depending on the type of award granted. Additionally, under the plan, the amount shown may increase by the number of shares currently unvested or forfeitable, or three times that number as applicable, that (i) fail to vest, (ii) are forfeited or cancelled, or (iii) correspond to the portion of any stock-based awards settled in cash.

SHARE REPURCHASE ACTIVITIES

Occidental’s share repurchase activities for the year ended December 31, 2012, were as follows:

Period	Total Number of Shares Purchased (a)		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 2012		144,542		$	104.84		—
Second Quarter 2012		1,760,000		$	81.19		1,760,000
Third Quarter 2012		583,072		$	86.58		470,000
October 1-31, 2012		620,000		$	80.24		620,000
November 1-30, 2012		2,860,000		$	75.90		2,860,000
December 1-31, 2012		1,520,000		$	74.92		1,520,000
Fourth Quarter 2012		5,000,000		$	76.14		5,000,000
Total 2012		7,487,614		$	78.69		7,230,000		17,255,575 (b)

(a) Includes shares purchased from the trustee of Occidental's defined contribution savings plan that are not part of publicly announced plans or programs.

(b) Occidental has had a 95 million share repurchase program authorized since 2008; however, the program does not obligate Occidental to acquire any specific number of shares and may be discontinued at any time.

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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 (S&P 500) and with that of Occidental’s peer group over the five-year period ended on December 31, 2012. The graph assumes that $100 was invested at the beginning of the five-year period shown in the graph below in (i) Occidental common stock, (ii) the stock of the companies in the S&P 500 and (iii) each of the peer group companies' common stock weighted by their relative market values within the peer group, and that all dividends were reinvested.

Occidental's peer group consists of Anadarko Petroleum Corporation, Apache Corporation, Canadian Natural Resources Limited, Chevron Corporation, ConocoPhillips, Devon Energy Corporation, EOG Resources Inc., ExxonMobil Corporation, Hess Corporation, Royal Dutch Shell plc, Total S.A. and Occidental.

	12/31/2007		12/31/2008		12/31/2009		12/31/2010		12/31/2011		12/31/2012
	$	100	$	79	$	110	$	135	$	131	$	110
		100		75		82		93		102		104
		100		63		80		92		94		109

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 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.

_______________________

(1) The cumulative total return of the peer group companies' common stock includes the cumulative total return of Occidental's common stock.

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ITEM 6 SELECTED FINANCIAL DATA

FIVE-YEAR SUMMARY OF SELECTED FINANCIAL DATA

Dollar amounts in millions, except per-share amounts

As of and for the years ended December 31,	2012				2011				2010			2009			2008
RESULTS OF OPERATIONS (a)
Net sales	$	24,172			$	23,939			$	19,045		$	14,814		$	23,713
Income from continuing operations (b)	$	4,635			$	6,640			$	4,569		$	3,151		$	7,183
Net income attributable to common stock	$	4,598			$	6,771			$	4,530		$	2,915		$	6,857
Basic earnings per common share from continuing operations (b)	$	5.72			$	8.16			$	5.62		$	3.88		$	8.77
Basic earnings per common share (b)	$	5.67			$	8.32			$	5.57		$	3.59		$	8.37
Diluted earnings per common share (b)	$	5.67			$	8.32			$	5.56		$	3.58		$	8.34
FINANCIAL POSITION (a)
Total assets	$	64,210			$	60,044			$	52,432		$	44,229		$	41,537
Long-term debt, net	$	7,023			$	5,871			$	5,111		$	2,557		$	2,049
Stockholders’ equity	$	40,048			$	37,620			$	32,484		$	29,159		$	27,325
MARKET CAPITALIZATION (c)	$	61,710			$	75,992			$	79,735		$	66,050		$	48,607
CASH FLOW
Operating:
Cash provided by operating activities	$	11,312			$	12,281			$	9,566		$	5,946		$	10,765
Investing:
Capital expenditures	$	(10,226	)		$	(7,518	)		$	(3,940	)	$	(3,245	)	$	(4,126	)
Cash used by all other investing activities, net	$	(2,429	)		$	(2,385	)	(d)	$	(5,355	)	$	(2,221	)	$	(5,314	)
Financing:
Cash dividends paid	$	(2,128	)	(e)	$	(1,436	)		$	(1,159	)	$	(1,063	)	$	(940	)
Cash provided (used) by all other financing activities, net	$	1,282			$	261			$	2,242		$	30		$	(570	)
DIVIDENDS PER COMMON SHARE	$	2.16			$	1.84			$	1.47		$	1.31		$	1.21
WEIGHTED AVERAGE BASIC SHARES OUTSTANDING (thousands)	809,345				812,075				812,472			811,305			817,635

Note:  Argentine operations were sold in February 2011 and have been reflected as discontinued operations for all applicable periods.

(a) See the MD&A section of this report and the Notes to Consolidated Financial Statements for information regarding acquisitions and dispositions, discontinued operations and other items affecting comparability.

(b) Represent amounts attributable to common stock after deducting noncontrolling interest amounts of $72 million in 2010, $51 million in 2009 and $116 million in 2008. There were no noncontrolling interests in 2012 and 2011.

(c) Market capitalization is calculated by multiplying the year-end total shares of common stock outstanding, net of shares held as treasury stock, by the year-end closing stock price.

(d) Includes $2.6 billion of cash received from the sale of the Argentine operations.

(e) Includes the accelerated fourth quarter 2012 dividend payment, which normally would have been accrued as of year end but paid in the first quarter of the following year.

ITEM 7 AND 7A

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (MD&A)

In this report, "Occidental" means Occidental Petroleum Corporation (OPC), or OPC and one or more entities in which it owns a controlling interest (subsidiaries). Occidental's principal businesses consist of three segments operated by OPC's subsidiaries and affiliates. The oil and gas segment explores for, develops and produces oil and condensate, natural gas liquids (NGLs) and natural gas. The chemical segment (OxyChem) mainly

manufactures and markets basic chemicals and vinyls. The midstream, marketing and other segment (midstream and marketing) gathers, processes, transports, stores, purchases and markets oil, condensate, NGLs, natural gas, carbon dioxide (CO₂)and power. It also trades around its assets, including transportation and storage capacity, and trades oil, NGLs, gas and other commodities. The segment also invests in entities that conduct similar activities.

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STRATEGY

General

Occidental aims to maximize total returns to stockholders using the following strategies:

Ø Grow oil and gas production through development programs focused on large, long-lived conventional and unconventional oil and gas assets with long-term growth potential, and acquisitions;

Ø Allocate and deploy capital with a focus on achieving returns well in excess of Occidental's cost-of-capital;

Ø Provide consistent dividend growth; and

Ø Maintain financial discipline and a strong balance sheet.

In conducting its business, Occidental accepts commodity, engineering and limited exploration risks. Occidental seeks to limit its financial and political risks.

Occidental prioritizes the use of its cash flows in the following order:

Ø Maintenance capital

Ø Dividends

Ø Growth capital

Ø Acquisitions

Ø Share repurchases

Capital is employed to operate all assets in a safe and environmentally sound manner. Management aims to develop Occidental's assets in a manner that they would contribute substantially to earnings and cash flow after invested capital. The following describes the application of Occidental's overall strategy to each of its operating segments.

Oil and Gas

Segment Earnings

($ millions)

Occidental prefers to hold large, long-lived "legacy" oil and gas assets, like those in California and the Permian Basin, that tend to have enhanced secondary and tertiary recovery opportunities and economies of scale that lead to cost-effective production. Occidental also focuses a portion of its drilling activities on unconventional shale opportunities.

The oil and gas business seeks to increase its oil and gas production profitably and add new reserves at a pace

ahead of production while minimizing costs incurred for finding and development of such reserves. The oil and gas business implements this strategy within the limits of the overall corporate strategy primarily by:

Ø Deploying capital to fully develop areas where reserves are known to exist and increase production from mature fields by applying appropriate technology and advanced reservoir-management practices;

Ø Adding reserves through a combination of focused exploration and development programs conducted in Occidental's core areas, which are the United States, the Middle East/North Africa and Latin America; and

Ø Maintaining a disciplined approach to acquisitions and divestitures with an emphasis on transactions at attractive prices.

Over the past several years, Occidental has strengthened its asset base within its core areas. Occidental has invested in, and disposed of, assets with the goal of raising the average performance and potential of its assets.

In 2012, Occidental paid approximately $2.3 billion for domestic oil and gas properties in the Permian Basin, the Williston Basin, California and South Texas.

Management currently believes Occidental's growth will be most strongly affected by the success of the development plans for its Permian, California and Oman assets and the Al Hosn gas project in Abu Dhabi where it continues to deploy significant capital. Occidental's oil and gas production has grown approximately five percent annually during the three-year period ended December 31, 2012.

Chemical

Segment Earnings

($ millions)

The primary objective of the chemical business is to generate cash flow in excess of its normal capital expenditure requirements and achieve above-cost-of-capital returns. The chemical segment's (OxyChem) 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 co-produced with caustic soda, and markets both to third parties. In addition, chlorine, together with ethylene, is converted through a series of intermediate products into PVC. OxyChem's focus on chlorovinyls allows it to maximize the benefits of integration and take advantage of

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economies of scale. Capital is employed to sustain production capacity and to focus on projects and developments designed to improve the competitiveness of segment assets. Acquisitions and plant development opportunities may be pursued when they are expected to enhance the existing core chlor-alkali and PVC businesses or take advantage of other specific opportunities. During 2012, OxyChem began construction of a chlor-alkali plant in Tennessee, which it expects to begin operating in the fourth quarter of 2013.

Midstream and Marketing

Segment Earnings

($ millions)

The midstream and marketing segment is managed to generate returns on capital employed in excess of Occidental's cost of capital. In order to generate these returns, the segment evaluates opportunities across the value chain and uses its assets to provide services to other segments and third parties. In marketing its own and third-party production, Occidental strives to maximize realized value using its assets, including transportation and storage capacity. In commodities trading, Occidental seeks to generate gains using net-long positions. The segment invests in and operates gas plants, co-generation facilities, pipeline systems and storage facilities. The segment also seeks to minimize the costs of gas, power and other commodities used in Occidental's businesses and to limit credit risk exposure. Capital is employed to sustain or, where appropriate, increase operational capacity and to improve the competitiveness of Occidental's assets. Occidental and Magellan Midstream Partners, L.P. are proceeding with the construction of the BridgeTex Pipeline which will transport crude oil between the Permian region and the Gulf Coast refinery markets and is expected to begin service in mid-2014.

Key Performance Indicators

General

Occidental seeks to meet its strategic goals by continually measuring its success in its key performance metrics that drive total stockholder return. In addition to production growth and capital allocation and deployment discussed above, Occidental believes the following are its most significant metrics:

Ø Cash margin per barrel;

Ø Free-cash-flow yield;

Ø Dividend growth;

Ø Return on equity (ROE) and return on capital employed (ROCE).

Occidental also monitors other segment-specific indicators such as per-unit profit, production costs and finding and development costs, as well as health, environmental and safety measures, like the number of recordable injuries, and others.

Based on the $2.56 per share annual dividend rate announced in February 2013, Occidental’s dividend rate has increased by 412 percent since 2002. While its stockholders' equity increased by 6 percent for 2012 and 37 percent for the three-year period from 2010 through 2012, Occidental continued to deliver above-cost-of-capital returns as follows:

	Annual 2012 (a)	Three-Year Annual Average 2010 - 2012 (b)
ROE	14.6%	15.2%
	{11.8%}
ROCE	12.6%	13.5%
	{10.3%}

(a) The top figures for ROE and ROCE for 2012 were calculated by dividing Occidental's 2012 income after removing the effect of Significant Items Affecting Earnings described on page 24 (while adding back after-tax interest expense for the ROCE calculation) by its average equity and capital employed, respectively, during 2012. We provide this adjusted measure because we believe it would be useful to investors in evaluating and comparing Occidental's performance between periods, not as a substitute for the measure calculated using net income. The bottom figure is the same calculation but using net income attributable to common stock in the numerator (while adding back after-tax interest expense for the ROCE calculation).

(b) The three-year average ROE and ROCE were calculated by dividing Occidental's average net income attributable to common stock (while adding back after-tax interest expense for the ROCE calculation) over the three-year period 2010-2012 by its average equity and capital employed, respectively, over the same period.

Debt Structure

Occidental issued $1.75 billion of senior unsecured notes in the second quarter of 2012 for general corporate purposes including ordinary course working capital increases, acquisitions, stock repurchases, retirement of debt and other business opportunities. As a result of Occidental’s commitment to financial discipline, its year-end 2012 total debt-to-capitalization (debt and equity) ratio was 16 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. The following table presents the average daily West Texas Intermediate (WTI), Brent and New York Mercantile Exchange (NYMEX) prices for 2012 and 2011:

	2012		2011
WTI oil ($/barrel)	$	94.21	$	95.12
Brent oil ($/barrel)	$	111.70	$	110.90
NYMEX gas ($/Mcf)	$	2.81	$	4.11

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The following table presents Occidental's average realized prices as a percentage of WTI, Brent and NYMEX for 2012 and 2011:

	2012		2011
Worldwide oil as a percentage of average WTI	106	%	103	%
Worldwide oil as a percentage of average Brent	89	%	88	%
Worldwide NGLs as a percentage of average WTI	48	%	58	%
Domestic natural gas as a percentage of NYMEX	93	%	99	%

Average realized oil prices were slightly higher in 2012 than 2011. Approximately 60 percent of Occidental’s oil production tracks world oil prices, such as Brent, and 40 percent tracks WTI. The average realized domestic natural gas price in 2012 decreased 35 percent from 2011.

Prices and differentials can vary significantly, even on a short-term basis, making it impossible to predict realized prices with a reliable degree of certainty.

Operations

Domestic Interests

Occidental conducts its domestic operations through land leases, subsurface mineral rights it owns or a combination of both surface land and subsurface mineral rights it owns. Occidental's domestic oil and gas leases have a primary term ranging from one to ten years, which is extended through the end of production once production commences. Of the total 8.1 million net acres in which Occidental has interests, approximately 74 percent is leased, 25 percent is owned subsurface mineral rights and 1 percent is owned land with mineral rights.

Production-Sharing Contracts (PSC)

Occidental has interests that are operated under PSCs or similar contracts in Bahrain, Iraq, Libya, Oman, Qatar and Yemen. Under such contracts, Occidental records a share of production and reserves to recover certain production costs and an additional share for profit. In addition, Occidental's share of production and reserves from operations in Long Beach, California, and certain contracts in Colombia 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 product prices rise and increases when prices decline. Overall, Occidental’s net economic benefit from these contracts is greater when product prices are higher.

Business Review

The following chart shows Occidental’s total volumes for the last five years:

Worldwide Production Volumes

(thousands BOE/day)

Notes:

• Includes average production volumes per day of 5 thousand barrels (mbbl), 6 mbbl and 6 mbbl for 2010, 2009 and 2008, respectively, related to the noncontrolling interest in a Colombian subsidiary.

• Excludes volumes from the Argentine operations sold in February 2011 and classified as discontinued operations.

United States Assets

United States

1. Permian

2. California

3. Midcontinent and Other interests

Permian

Occidental's Permian production is diversified across a large number of producing areas in the 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, accounting for approximately 15 percent of the total United States oil production.

Occidental is the largest producer of oil in the Permian Basin with an approximate 16 percent net share of the total oil production. Occidental also produces and processes natural gas and NGLs in the Permian Basin. Occidental continued to increase its Permian interests in 2012 through various acquisitions, a significant portion of which related to its non-CO₂ operations which comprised approximately 1.5 million net acres at the end of 2012.

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

Occidental’s interests in Permian offer significant additional development and exploitation potential. During 2012, Occidental drilled approximately 550 wells on its operated properties and participated in additional wells drilled on third-party-operated properties. Occidental also focused on improving the performance of existing wells.

Occidental's Permian non-CO₂ operations are among its fastest growing assets. Since beginning significant delineation and development efforts in 2010, production from these operations has increased by more than 25 percent. The development program continued to increase in 2012 accounting for more than 300 of the wells drilled in Permian.

Occidental's share of production in Permian was approximately 207,000 BOE per day in 2012.

California

Occidental's California operations include interests in the Elk Hills area, the Wilmington and other fields in the Los Angeles Basin and the Ventura, San Joaquin and Sacramento Basins. Occidental has properties in more than 125 fields in California, an increase from 2011 resulting from various property acquisitions in 2012.

Occidental's interests in the Elk Hills area include the Elk Hills oil and gas field in the southern portion of California’s San Joaquin Valley, which it operates with an approximate 78-percent interest, along with other adjacent properties. The Elk Hills Field is the largest producer of gas and NGLs in California. During 2012, Occidental continued to invest in the Elk Hills area, performing infill drilling, field extensions and recompletions identified by advanced reservoir characterization techniques, resulting in approximately 320 new wells being drilled.

Occidental began operating a new gas processing plant in Elk Hills in 2012 with capacity to handle 200 million cubic feet per day.

Occidental's share of production in California was approximately 148,000 BOE per day in 2012.

Occidental holds approximately 2.1 million net acres in California, the large majority of which are net fee mineral interests. As a result, Occidental has a substantial inventory of properties available for future development and exploitation in conventional areas, as well as unconventional prospects, such as shale. Occidental drilled approximately 760 wells in California during 2012.

Midcontinent and Other

The Midcontinent and Other properties include interests in the Hugoton Field, the Piceance Basin, the Williston Basin, the Marcellus Shale in the Appalachian Basin, the Eagle Ford Shale and other areas in South Texas. These properties are located in Kansas, Oklahoma, Colorado, North Dakota, West Virginia and Texas. Occidental holds over 2.3 million net acres in the Midcontinent region, which includes 1.4 million net acres in a large concentration of gas reserves and production and royalty interests in the Hugoton area and approximately 0.4 million net acres in the Piceance area. Occidental also holds approximately 160,000 net acres in South Texas, including 4,000 net acres in the Eagle Ford Shale, which was acquired in 2012. In addition, Occidental holds approximately 341,000 net acres of oil producing and prospective unconventional properties in the Williston Basin's Bakken and Three Forks formations. In addition, Occidental holds approximately 235,000 net acres in West Virginia.

In Midcontinent and Other, Occidental drilled approximately 260 wells and produced approximately 110,000 BOE per day in 2012.

Other Developments

Management conducted a review of Occidental’s portfolio of oil and gas assets in the fourth quarter of 2012 and concluded that, given the current and anticipated natural gas pricing environment and the effect of reserve revisions from price changes and well performance, certain of its domestic natural gas producing properties had become impaired. Occidental also concluded that certain projects had become uneconomical and that it would not pursue them. As a result, Occidental recorded pre-tax impairment charges of $1.7 billion, almost all of which were for certain assets in Midcontinent, over 90 percent of which were related to natural gas properties that were acquired more than four years ago on average when gas prices were more than $6 per Mcf.

Middle East/North Africa Assets

Middle East/North Africa

1. Bahrain

2. Iraq

3. Libya

4. Oman

5. Qatar

6. United Arab Emirates

7. Yemen

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Bahrain

In 2009, Occidental and other consortium members began operating the Bahrain Field under a 20-year development and production sharing agreement (DPSA). Occidental has a 48-percent working interest in the joint venture. Since handover of operations, the consortium has increased gross gas production capacity more than 60 percent from an initial level of 1.5 billion cubic feet per day to over 2.4 billion cubic feet per day and increased gross oil production from 26,000 barrels per day to 42,000 barrels per day. The consortium plans to continue growing gross gas production capacity to over 2.7 billion cubic feet per day and gross oil production to over 75,000 barrels per day. Occidental's share of production from Bahrain during 2012 was approximately 232 million cubic feet (MMcf) per day of gas and 4,000 barrels of oil per day.

Iraq

In 2010, Occidental and other consortium members signed a 20-year contract with the South Oil Company of Iraq to develop the Zubair Field. Occidental has a 23.44-percent interest in this contract, which entitles Occidental to receive oil for cost recovery and a remuneration fee, as a result of having achieved an initial gross production threshold in 2010. The consortium plans to increase production to a contractually targeted production level of 1.2 million BOE per day by 2016 and maintain this level of production for seven years. Occidental's share of production from Iraq was approximately 11,000 BOE per day in 2012.

Libya

Occidental participates with subsidiaries of the Libyan National Oil Company in Sirte Basin producing operations. These agreements continue through 2032. The 2012 production volume was approximately 12,000 BOE per day.

Oman

In Oman, Occidental is the operator of Block 9 and Block 27, with a 65-percent working interest in each block; Block 53, with a 45-percent working interest; and Block 62, with a 48-percent working interest.

A 30-year PSC for the Mukhaizna Field (Block 53) was signed with the Government of Oman in 2005, pursuant to which Occidental assumed operation of the field. By the end of 2012, Occidental had drilled almost 1,800 new wells and continued implementation of a major steamflood project. In 2012, the average gross daily production was 120,000 BOE per day, which was over 15 times higher than the production rate in September 2005.

The term for Block 9 continues through 2015, with a 10-year extension right for certain areas. The term for Block 27 expires in 2035.

In 2008, Occidental was awarded a 20-year contract for Block 62, subject to declaration of commerciality, where it is pursuing development and exploration opportunities targeting gas and condensate resources.

Occidental's share of production from Oman was approximately 76,000 BOE per day in 2012.

Qatar

In Qatar, Occidental is the operator at Idd El Shargi North Dome (ISND) and Idd El Shargi South Dome (ISSD), with a 100-percent working interest in each, and Al Rayyan (Block 12), with a 92.5-percent working interest. The terms for ISND, ISSD and Block 12 expire in 2019, 2022 and 2017, respectively.

In 2011, Occidental received approval from the Government of Qatar for the fourth phase of field development of the ISND Field, focusing on continued development of mature reservoirs while further delineating and developing less mature reservoirs. Occidental also received approval for field development plans for ISSD and Al Rayyan, which include additional drilling through 2013.

Occidental's Dolphin investment comprises two separate economic interests through which Occidental owns: (i) a 24.5-percent undivided interest in the upstream operations under a DPSA with the Government of Qatar to develop and produce natural gas and NGLs in Qatar’s North Field through mid-2032, with a provision to request a five-year extension; and (ii) a 24.5-percent interest in the stock of Dolphin Energy Limited (Dolphin Energy), which is discussed further in "Midstream, Marketing and Other Segment – Pipeline Transportation."

Occidental's share of production from Qatar was approximately 114,000 BOE per day in 2012.

United Arab Emirates

In the first quarter of 2011, Occidental acquired a 40-percent participating interest in the Al Hosn gas project, joining with the Abu Dhabi National Oil Company (ADNOC) in a 30-year joint venture agreement. The project is anticipated to produce over 500 MMcf per day of natural gas, of which Occidental’s net share would be over 200 MMcf per day. In addition, the project is expected to produce over 50,000 barrels per day of NGLs and condensates, of which Occidental’s net share would be over 20,000 barrels per day. Occidental’s 2012 capital expenditures for this project were approximately $1.2 billion. A substantial portion of the total expenditures to date has been incurred in connection with plants and facilities and is included in the midstream and marketing segment. As the development progresses, higher portions of the capital expenditures will be spent to drill wells, which will be reflected in the oil and gas segment. Occidental believes that its share of total 2013 capital for the project will be approximately $1.1 billion.

Occidental conducts a majority of its Middle East business development activities through its office in Abu Dhabi, which also provides various support functions for Occidental’s Middle East/North Africa oil and gas operations.

Yemen

In Yemen, Occidental owns interests in: Block 10 East Shabwa Field, which extends through 2015 with a 40.4-percent interest that includes an 11.8-percent interest held in an unconsolidated entity, and Block S-1 An Nagyah Field, which is an Occidental-operated block with a 75-percent working interest that extends into 2023.

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Occidental's share of production from the Yemen properties was approximately 14,000 BOE per day in 2012.

Latin America Assets

Latin America 1. Bolivia
2. Colombia

Bolivia

Occidental holds working interests in the Tarija, Chuquisaca and Santa Cruz regions of Bolivia, which produce gas.

Colombia

Occidental has a working interest in the La Cira-Infantas area and has operations within the Llanos Norte Basin. Occidental's interests range from 39 to 61 percent and certain interests expire between 2023 and 2030, while others extend through the economic limit of the areas. Occidental's share of production was approximately 29,000 BOE per day in 2012.

Proved Reserves

Proved oil, NGL and gas reserves were estimated using the unweighted arithmetic average of the first-day-of-the-month price for each month within the year, unless prices were defined by contractual arrangements. Oil, NGL and gas prices used for this purpose were based on posted benchmark prices and adjusted for price differentials including gravity, quality and transportation costs. For the 2012, 2011 and 2010 disclosures, the calculated average West Texas Intermediate oil prices were $94.71, $96.19 and $79.43 per barrel, respectively. The calculated average Henry Hub gas prices for 2012, 2011 and 2010 disclosures were $2.79, $4.04 and $4.39 per MMBtu, respectively.

Occidental had proved reserves at year-end 2012 of 3,296 million BOE, as compared with the year-end 2011 amount of 3,176 million BOE. Proved reserves at year-end 2012 and 2011 consisted of, respectively, 62 percent and 63 percent oil, 10 percent and 9 percent NGLs and 28 percent and 28 percent natural gas. Proved developed reserves represented approximately 73 percent and 76 percent, respectively, of Occidental’s total proved reserves at year-end 2012 and 2011.

Occidental does not have any reserves from non-traditional sources. For further information regarding Occidental's proved reserves, see "Supplemental Oil and Gas Information" following the "Financial Statements."

Proved Reserve Additions

Occidental's total proved reserve additions from all sources were 400 million BOE in 2012.  The total additions were as follows:

In millions of BOE
Improved recovery	257
Extensions and discoveries	232
Purchases	94
Revisions of previous estimates	(183	)
Total additions	400

Occidental's ability to add reserves, other than through purchases, depends on the success of improved recovery, extension and discovery projects, each of which depends on reservoir characteristics, technology improvements and oil and natural gas prices, as well as capital and operating costs. Many of these factors are outside of management’s control, and will affect whether these historical sources of proved reserve additions continue at similar levels.

Improved Recovery

In 2012, Occidental added proved reserves of 257 million BOE from improved recovery through its EOR and infill drilling activities. Generally, the improved recovery additions in 2012 were associated with the continued development of properties in California, Permian, South Texas and Oman. These properties comprise both conventional projects, which are characterized by the deployment of EOR development methods, largely employing application of waterflood, steamflood or CO₂ injection, and unconventional projects. These types of conventional EOR development methods are often applied through existing wells, though additional drilling may be required to fully optimize the development configuration. Waterflooding is the technique of injecting water into the formation to displace the oil to the offsetting oil production wells. Steamflooding is the technique of injecting steam into the formation to lower oil viscosity so that it flows more freely into producing wells. This process is applied in areas where the oil is too viscous to be effectively moved with water. CO₂ flooding involves injecting CO₂ into oil reservoirs where it causes the oil to flow more freely into producing wells. Many of Occidental's projects, including unconventional projects, rely on improving permeability to increase flow in the wells. In addition, some improved recovery comes from drilling infill wells that allow recovery of reserves that would not be recoverable from existing wells.

Extensions and Discoveries

Occidental also obtained reserve additions from extensions and discoveries, which are dependent on successful exploration and exploitation programs. In 2012, extensions and discoveries added 232 million BOE, a substantial majority of which is attributable to the

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recognition of initial proved undeveloped reserves from the Al Hosn gas project.

Purchases and Divestitures of Proved Reserves

Occidental continues to add reserves through acquisitions when properties are available at prices it deems reasonable. As market conditions change, the available supply of properties may increase or decrease accordingly. In 2012, Occidental added 94 million BOE through purchases of proved reserves largely consisting of several domestic acquisitions in the Permian Basin, California, Williston Basin and South Texas.

Revisions of Previous Estimates

Revisions can include upward or downward changes to previous proved reserve estimates for existing fields due to the evaluation or interpretation of geologic, production decline or operating performance data. In addition, product price changes affect proved reserves recorded by Occidental. For example, higher prices may increase the economically recoverable reserves, particularly for domestic properties, because the extra margin extends the expected life of the operations. Offsetting this effect, higher prices decrease Occidental's share of proved reserves under PSCs because less oil is required to recover costs. Conversely, when prices drop, Occidental's share of proved reserves increases for PSCs and economically recoverable reserves may drop for other operations. In 2012, revisions of previous estimates provided a net 183 million BOE reduction to proved reserves.

In 2012, revisions related to price for the company as a whole were negative. A substantial majority of such revisions related to Occidental's domestic gas reserves and resulted from lower domestic gas prices. These lower prices and the resulting changes in Occidental's plans for drilling on gas properties constituted a majority of its total revisions. To the extent gas prices recover in the future, a portion of these reserves will be reinstated. If natural gas prices decrease further for an extended period, domestic gas reserves could experience additional negative price revisions.

Other negative revisions were mainly due to reservoir performances in Elk Hills and Midcontinent and Other. The revisions involved several properties where wells experienced higher-than-expected decline rates. Sizable portions of these revisions were transferred from the proved category to probable, possible and contingent categories.

Reserve estimation rules require that estimated ultimate recoveries be much more likely to increase or remain constant than to decrease as changes are made due to increased availability of technical data. As a result, apart from the effect of product prices, it is generally more likely that future proved reserve revisions will be positive in aggregate over time rather than negative.

Proved Undeveloped Reserves

In 2012, Occidental had proved undeveloped reserve additions of 443 million BOE from improved recovery, extensions and discoveries and purchases. Of the total additions, 171 million BOE represented additions from

improved recovery, primarily in California, Permian, South Texas and Oman. Occidental added 46 million BOE through purchases of proved undeveloped reserves domestically in the Permian and Williston Basins and California. Additionally, the proved undeveloped reserves increased due to extensions and discoveries mainly from the Al Hosn gas project. These proved undeveloped reserve additions were offset by transfers of 229 million BOE to the proved developed category as a result of the 2012 development programs and by revisions of 98 million BOE, which is included in total revisions discussed above. These revisions were in the same locations as those discussed above and factors that caused them were substantially the same as those that caused the changes to total proved reserves. Occidental incurred approximately $3.4 billion in 2012 to convert proved undeveloped reserves to proved developed reserves. Permian, Bahrain, California, Oman and Williston accounted for approximately 86 percent of the reserves transfers from proved undeveloped to proved developed in 2012. Costs to develop proved undeveloped reserves have increased over time and may continue to increase.

Reserves Evaluation and Review Process

Occidental’s estimates of proved reserves and associated future net cash flows as of December 31, 2012, were made by Occidental’s technical personnel and are the responsibility of management. The estimation of proved reserves is based on the requirement of reasonable certainty of economic producibility and funding commitments by Occidental to develop the reserves. This process involves reservoir engineers, geoscientists, planning engineers and financial analysts. As part of the proved reserves estimation process, all reserves volumes are estimated by a forecast of production rates, operating costs and capital expenditures. Price differentials between benchmark prices (the unweighted arithmetic average of the first-day-of-the-month price for each month within the year) and realized prices 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 analysis, type-curve analysis, material balance calculations that take into account the volumes of substances replacing the volumes produced and associated reservoir pressure changes, seismic analysis and computer simulation of the reservoir performance. These field-tested technologies have demonstrated reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. Operating and capital costs are forecast using the current cost environment applied to expectations of future operating and development activities.

Net proved developed reserves are those volumes that are expected to be recovered through existing wells with existing equipment and operating methods for which the incremental cost of any additional required investment is relatively minor. Net proved undeveloped reserves are those volumes that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

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The current Senior Vice President, Reserves for Oxy Oil and Gas is responsible for overseeing the preparation of reserve estimates, in compliance with SEC rules and regulations, including the internal audit and review of Occidental's oil and gas reserves data. The Senior Vice President has over 30 years of experience in the upstream sector of the exploration and production business, and has held various assignments in North America, Asia and Europe. He is a three-time past Chair of the Society of Petroleum Engineers Oil and Gas Reserves Committee. He is an American Association of Petroleum Geologists (AAPG) Certified Petroleum Geologist and currently serves on the AAPG Committee on Resource Evaluation. He is a member of the Society of Petroleum Evaluation Engineers, the Colorado School of Mines Potential Gas Committee and the UNECE Expert Group on Resource Classification. He is also an active member of the Joint Committee on Reserves Evaluator Training (JCORET). The Senior Vice President has Bachelor of Science and Master of Science degrees in geology from Emory University in Atlanta.

Occidental has a Corporate Reserves Review Committee (Reserves Committee), consisting of senior corporate officers, to review and approve Occidental's oil and gas reserves. The Reserves Committee reports to the Audit Committee of Occidental's Board of Directors during the year. Since 2003, Occidental has retained Ryder Scott Company, L.P. (Ryder Scott), independent petroleum engineering consultants, to review its annual oil and gas reserve estimation processes.

In 2012, Ryder Scott conducted a process review of Occidental’s methods and analytical procedures utilized by Occidental’s engineering and geological staff for estimating the proved reserves volumes, preparing the economic evaluations and determining the reserves classifications as of December 31, 2012, in accordance with the U.S. Securities and Exchange Commission (SEC) regulatory standards. Ryder Scott reviewed the specific application of such methods and procedures for selected oil and gas properties considered to be a valid representation of Occidental’s 2012 year-end total proved reserves portfolio. In 2012, Ryder Scott reviewed approximately 20 percent of Occidental’s proved oil and gas reserves. Since being engaged in 2003, Ryder Scott has reviewed the specific application of Occidental’s reserve estimation methods and procedures for approximately 70 percent of Occidental’s existing proved oil and gas reserves. Management retains Ryder Scott to provide objective third-party input on its methods and procedures and to gather industry information applicable to Occidental’s reserve estimation and reporting process. Ryder Scott has not been engaged to render an opinion as to the reasonableness of reserves quantities reported by Occidental. Occidental has filed Ryder Scott's independent report as an exhibit to this Form 10-K.

Based on its reviews, including the data, technical processes and interpretations presented by Occidental, Ryder Scott has concluded that the overall procedures and methodologies Occidental utilized in estimating the proved reserves volumes for the reviewed properties are appropriate for the purpose thereof and comply with current SEC regulations.

Industry Outlook

The petroleum industry is highly competitive and subject to significant volatility due to numerous current and anticipated market conditions. The WTI and Brent oil price indexes have fluctuated throughout 2012, settling at $91.82 per barrel and $111.11 per barrel as of December 31, 2012.

Oil prices will continue to be affected by (i) global supply and demand, which are generally a function of global economic conditions, inventory levels, production disruptions, technological advances, regional market conditions and the actions of OPEC, other significant producers and governments, (ii) currency exchange rates and (iii) the effect of changes in these variables on market perceptions. These factors make it impossible to predict the future direction of oil prices reliably. Occidental continues to adjust to economic conditions by adjusting capital expenditures in line with current economic conditions with the goal of keeping returns well above its cost of capital.

NGL prices are related to the supply and demand for the components of products making up these liquids. Some of them more typically correlate to the price of oil while others are affected by natural gas prices as well as the demand for certain chemical products for which they are used as feedstock. In addition, infrastructure constraints magnify the pricing volatility from region to region. The volatility in all of these markets makes it impossible to predict NGL prices reliably.

Domestic natural gas prices and local differentials are strongly affected by local supply and demand fundamentals, as well as government regulations and availability of transportation capacity from producing areas. These and other factors can cause prices to be volatile, making it impossible to predict domestic gas prices reliably. International gas prices are generally fixed under long-term contracts.

CHEMICAL SEGMENT

Business Environment

Chemical segment earnings decreased in 2012, notably because margins were lower across most product lines as price and volume declines more than offset lower feedstock costs. While the overall United States economy experienced modest growth, the lower margins were primarily due to weaker economic conditions in Europe and Asia, and increased competitive activity from these regions.

Business Review

Basic Chemicals

During 2012, United States manufacturing sectors experienced weak growth much of the year, resulting in soft domestic demand and pricing for basic chemical products. Industry chlorine production decreased by approximately 2 percent, compared to 2011. Chlorine prices decreased throughout the year due to lower chlorine demand caused by the slowdown of the Chinese economy and the European debt crisis. Exports of downstream chlorine derivatives into the vinyls chain remained competitive in offshore markets as a result of the North America feedstock cost advantages, which are driven mostly by natural gas prices. Pricing for liquid caustic soda began 2012 generally

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soft because the markets anticipated increasing supply due to the improving United States economy. Prices improved in the last two quarters of 2012 as a result of favorable global caustic soda supply and demand balances, resulting in prices finishing slightly above the prior year level. Businesses such as calcium chloride and potassium hydroxide were also negatively impacted by a mild winter and drought conditions in the United States.

During 2012, OxyChem began construction of a 182,500-ton-per-year membrane chlor-alkali plant in Tennessee, which it expects to begin operating in the fourth quarter of 2013.

Vinyls

Demand in the domestic housing and commercial construction markets increased, resulting in a year-over-year domestic vinyl demand increase of approximately 8 percent in 2012. The higher domestic demand combined with a modest growth in exports contributed to an approximately 4-percent industry-wide increase in domestic operating rates compared to 2011. Industry margins also increased in 2012 due to a combination of higher PVC selling prices and lower ethylene costs. Ethylene costs, which are a significant component of PVC feedstock costs, increased outside North America in 2012 due to the greater dependence on naphtha-based production versus ethane in the United States. North American-produced ethylene continues to be cost-competitive versus prices in Europe and Asia, giving North American vinyl products an advantage in global markets. Industry-wide North American exports of PVC accounted for greater than 35 percent of the total sales of North American producers.

Industry Outlook

Industry performance will depend on the health of the global economy, specifically in the housing, construction, automotive and durable goods markets. Margins also depend on market supply and demand balances and feedstock and energy prices.

Basic Chemicals

Occidental expects that if the United States housing, automotive and durable goods markets continue to improve, domestic demand for basic chemical products should be higher in 2013. With improving demand, chlorine and caustic soda margins would be expected to remain at least at 2012 levels. The continued competitiveness of downstream chlorine derivatives in global markets is contingent on United States feedstock costs, primarily natural gas and ethylene, remaining favorable compared to other global markets.

Vinyls

North American demand and operating rates for vinyls should improve further in 2013 if growth of housing starts and commercial construction continues. Occidental expects export demand to remain firm and industry margins to improve as operating rates increase.

MIDSTREAM AND MARKETING SEGMENT

Business Environment

Midstream and marketing segment earnings are affected by the performance of its marketing and trading businesses and its processing, transportation and power generation assets. The marketing and trading businesses aggregate and market Occidental's and third-party volumes, trade oil, gas and other commodities and engage in storage activities. Earnings related to processing and transportation are affected by the volumes that are processed at, and transported through, the segment's plants and pipelines, as well as the margins obtained on related services.

The midstream and marketing segment earnings in 2012 were comparable to 2011 and reflected improved marketing and trading performance offset by lower gas processing margins.

Business Review

Oil and Gas Marketing and Trading

The marketing and trading group markets substantially all of Occidental’s oil, NGLs and gas production, trades around its assets, including transportation and storage capacity, and engages in commodities trading. Occidental’s third-party marketing and trading activities focus on purchasing oil, NGLs and gas for resale from parties whose oil and gas supply is located near its transportation and storage assets. These purchases allow Occidental to aggregate volumes to improve marketing earnings. In addition, Occidental’s Phibro trading unit's strategy is to profit from market price changes. Marketing and trading performance is affected primarily by commodity price changes and margins in oil and gas transportation and storage programs. The marketing and trading group's earnings increased in 2012.

Gas Processing Plants and CO₂ Fields and Facilities

Occidental processes its and third-party domestic wet gas to extract NGLs and other gas byproducts, including CO₂, and delivers dry gas to pipelines. Margins primarily result from the difference between inlet costs of wet gas and market prices for NGLs. Occidental’s 2012 earnings from these operations decreased compared to 2011, which reflected lower NGL prices.

Occidental, together with ADNOC, is constructing a gas plant and facilities as part of the Al Hosn gas project in Abu Dhabi, which is expected to be operational in 2014.

Pipeline Transportation

Margin and cash flow from pipeline transportation operations mainly reflect volumes shipped. Dolphin Energy owns and operates a 230-mile-long, 48-inch-diameter natural gas pipeline (Dolphin Pipeline), which transports dry natural gas from Qatar to the UAE and Oman. The Dolphin Pipeline contributes significantly to Occidental's pipeline transportation results through Occidental's 24.5-percent interest in Dolphin Energy. The Dolphin Pipeline has capacity to transport up to 3.2 Bcf of natural gas per day and currently transports approximately 2.3 Bcf per day. Demand for natural gas in the UAE and Oman has grown and Dolphin Energy’s customers have requested additional

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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.

Occidental owns an oil common carrier pipeline and storage system with approximately 2,700 miles of pipelines from southeast New Mexico across the Permian Basin of southwest Texas to Cushing, Oklahoma. The system has a current throughput capacity of about 365,000 barrels per day, 5.8 million barrels of active storage capability and 85 truck unloading facilities at various points along the system, which allow for additional volumes to be delivered into the pipeline.

Occidental owns 35 percent of the general partner of Plains All-American Pipeline, L.P. (Plains Pipeline), a publicly traded oil and gas pipeline transportation, storage, terminalling and marketing entity in the western and southern United States and Canada. The Plains Pipeline contributed over 20 percent of the segment's earnings for 2012.

Occidental and Magellan Midstream Partners, L.P. are proceeding with the construction of the BridgeTex Pipeline, which is expected to begin service in mid-2014. The approximately 450-mile-long pipeline will be capable of transporting approximately 300,000 barrels per day of crude oil between the Permian region (Colorado City, TX) and the Gulf Coast refinery markets. The BridgeTex Pipeline project also includes construction of approximately 2.6 million barrels of oil storage in aggregate.

Occidental's 2012 pipeline transportation earnings improved due to higher volumes and pricing, and higher income from Plains Pipeline, partially offset by lower earnings from the Dolphin Pipeline.

Power Generation Facilities

Earnings from power and steam generation facilities are derived from sales to affiliates and third parties and are generally not material.  

Industry Outlook

The pipeline transportation and power generation businesses are expected to remain relatively stable. The gas processing plant operations could have volatile results depending mostly on NGL prices, which cannot be predicted. Generally, higher NGL prices result in higher profitability. Based on its framework of controls and risk management systems, however, Occidental does not expect the volatility of these operations to be significant to the company as a whole. Although the marketing and the trading businesses individually can cause volatility, the operations together tend to offset each other, significantly reducing the overall volatility of the midstream and marketing segment.

SEGMENT RESULTS OF OPERATIONS

Segment earnings exclude income taxes, interest income, interest expense, environmental remediation expenses, unallocated corporate expenses and discontinued operations, but include gains and losses from dispositions of segment assets and income from the segments' equity investments. Seasonality is not a primary driver of changes in Occidental's consolidated quarterly earnings during the year.

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,	2012			2011			2010
NET SALES(a)
Oil and Gas	$	18,906		$	18,419		$	14,276
Chemical	4,580			4,815			4,016
Midstream and Marketing	1,399			1,447			1,471
Eliminations (a)	(713		)	(742		)	(718		)
	$	24,172		$	23,939		$	19,045
EARNINGS
Oil and Gas (b,c)	$	7,095		$	10,241		$	7,151
Chemical	720			861			438
Midstream and Marketing	439			448			472
	8,254			11,550			8,061
Unallocated corporate items
Interest expense, net (d)	(117		)	(284		)	(93		)
Income taxes (e)	(3,118		)	(4,201		)	(2,995		)
Other	(384		)	(425		)	(404		)
Income from continuing operations (b)	4,635			6,640			4,569
Discontinued operations, net (f)	(37		)	131			(39		)
Net Income (b)	$	4,598		$	6,771		$	4,530
Basic Earnings per Common Share	$	5.67		$	8.32		$	5.57

(a) Intersegment sales eliminate upon consolidation and are generally made at prices approximating those that the selling entity would be able to obtain in third-party transactions.

(b) Oil and gas segment earnings, income from continuing operations and net income represent amounts attributable to common stock after deducting a noncontrolling interest amount of $72 million for 2010.

(c) The 2012 amount includes pre-tax charges of $1.7 billion for the impairment of domestic gas assets and related items. The 2011 amount includes pre-tax charges of $35 million related to exploration write-offs in Libya and $29 million related to a Colombian net worth tax, and a pre-tax gain for the sale of an interest in a Colombian pipeline of $22 million. The 2010 amount includes a $275 million pre-tax charge for asset impairments, predominately of gas properties in the Rocky Mountain region.  

(d) The 2011 amount includes a pre-tax charge of $163 million related to the premium on debt extinguishment.

(e) The 2011 amount includes a net $21 million charge for out-of-period state income taxes. The 2010 amount includes an $80 million benefit related to foreign tax credit carryforwards.  

(f) The 2011 amount includes a $144 million after-tax gain from the sale of the Argentine operations.  

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Oil and Gas

Dollars in millions, except as indicated

	2012			2011		2010
Segment Sales	$	18,906		$	18,419	$	14,276
Segment Earnings	$	7,095	(a)	$	10,241	$	7,151

(a) Includes pre-tax charges of $1.7 billion for the impairment of domestic gas assets and related items.

The following tables set forth the production and sales volumes of oil, NGLs and natural gas per day for each of the three years in the period ended December 31, 2012. The differences between the production and sales volumes per day are generally due to the timing of shipments at Occidental’s international locations where product is loaded onto tankers.

Production per Day	2012	2011	2010
United States
Oil (MBBL)
California	88	80	76
Permian	142	134	136
Midcontinent and Other	25	16	7
Total	255	230	219
NGLs (MBBL)
California	17	15	16
Permian	39	38	29
Midcontinent and Other	17	16	7
Total	73	69	52
Natural gas (MMCF)
California	256	260	280
Permian	155	157	199
Midcontinent and Other	410	365	198
Total	821	782	677
Latin America (a)
Oil (MBBL) – Colombia (b)	29	29	37
Natural gas (MMCF) – Bolivia	13	15	16
Middle East/North Africa
Oil (MBBL)
Bahrain	4	4	3
Dolphin	8	9	11
Oman	67	67	62
Qatar	71	73	76
Other	36	38	46
Total	186	191	198
NGLs (MBBL)
Dolphin	8	10	13
Other	1	—	1
Total	9	10	14
Natural gas (MMCF)
Bahrain	232	173	169
Dolphin	163	199	236
Oman	57	54	48
Total	452	426	453
Total Production (MBOE) (a,c)	766	733	711
(See footnotes following the Average Sales Price table)

Sales Volumes per Day	2012	2011	2010
United States
Oil (MBBL)	255	230	219
NGLs (MBBL)	73	69	52
Natural gas (MMCF)	819	782	677
Latin America (a)
Oil (MBBL) – Colombia (b)	28	29	36
Natural gas (MMCF) – Bolivia	13	15	16
Middle East/North Africa
Oil (MBBL)
Bahrain	4	4	3
Dolphin	8	9	12
Oman	66	69	61
Qatar	71	73	76
Other	36	34	42
Total	185	189	194
NGLs (MBBL)
Dolphin	8	10	12
Other	1	—	1
Total	9	10	13
Natural gas (MMCF)	452	426	453
Total Sales Volumes (MBOE) (a,c)	764	731	705
(See footnotes following the Average Sales Prices table)

	2012		2011		2010
Average Sales Prices
Oil Prices ($ per bbl)
United States	$	93.72	$	92.80	$	73.79
Latin America (a)	$	98.35	$	97.16	$	75.29
Middle East/North Africa	$	108.76	$	104.34	$	76.67
Total worldwide (a)	$	99.87	$	97.92	$	75.16
NGL Prices ($ per bbl)
United States	$	46.07	$	59.10	$	48.86
Middle East/North Africa	$	37.74	$	32.09	$	30.64
Total worldwide	$	45.18	$	55.53	$	45.08
Gas Prices ($ per Mcf)
United States	$	2.62	$	4.06	$	4.53
Latin America (a)	$	11.85	$	10.11	$	7.73
Total worldwide (a)	$	2.06	$	3.01	$	3.11
Expensed Exploration	$	345	$	258	$	262
Capital Expenditures
Development	$	7,554	$	5,686	$	2,955
Exploration	$	622	$	421	$	194
Other	$	44	$	38	$	17

(a) For all periods presented, excludes volumes and amounts from the Argentine operations sold in February 2011 and classified as discontinued operations.

(b) Includes production and sales volumes per day of 5 mbbl and 4 mbbl, respectively, for the year ended December 31, 2010, related to the noncontrolling interest in a Colombian subsidiary.  

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

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Oil and gas segment earnings in 2012 were $7.1 billion compared to $10.2 billion in 2011. The decrease reflected asset impairments and related items, lower NGL and natural gas prices, and higher depreciation depletion and amortization (DD&A) rates, maintenance activity and field support costs and exploration expense, partially offset by higher oil prices and domestic volumes.

Average production costs for 2012, excluding taxes other than on income, were $14.99 per BOE, compared to $12.84 per BOE for 2011. The increase reflected higher maintenance activities and field support costs. The fourth quarter of 2012 production costs were $14.95 per barrel, which was $1.04 per barrel lower than the third quarter of 2012 level. These reductions occurred during the course of the fourth quarter, and the 2012 year-end exit rate on a per barrel basis was lower than the fourth quarter 2011 average and well below the fourth quarter 2012 level. These reductions are expected to continue into 2013, reflecting planned improvements in operational efficiencies over many cost categories.

Average daily oil and gas production volumes were 766,000 BOE for 2012, compared to 733,000 BOE for 2011. Occidental's domestic production increased by 9 percent, while total company production increased by 5 percent. Dolphin's full cost recovery of pre-startup capital, which reduced production, was the only operation where PSCs and similar contracts had an appreciable effect on 2012 production volumes. Average daily sales volumes were 764,000 BOE in the twelve months of 2012, compared with 731,000 BOE for the same period in 2011.

Oil and gas segment earnings in 2011 were $10.2 billion compared to $7.2 billion in 2010. The increase reflected higher oil and NGL prices and volumes, partially offset by higher DD&A rates and higher operating costs, including higher field support, workover and well maintenance expenses driven by Occidental’s program to increase production at current high oil prices.

Average daily oil and gas production volumes were 733,000 BOE for 2011, compared with 711,000 BOE for 2010. The increase was mainly due to acquisitions in South Texas, California and the Williston Basin and higher production in Oman’s Mukhaizna Field and Iraq, which were partially offset by lower production in Libya. Production was negatively impacted in the Middle East/North Africa, Colombia and Long Beach by higher year-over-year average oil prices affecting PSCs by 18,000 BOE per day. Average daily sales volumes were 731,000 BOE in the twelve months of 2011, compared with 705,000 BOE for 2010.

Oil and gas segment earnings in 2012 included pre-tax charges of $1.7 billion for the impairment of domestic gas assets and related items.

Oil and gas segment earnings in 2011 included pre-tax charges of $35 million related to exploration write-offs in Libya and $29 million related to Colombia net worth tax, as well as a pre-tax gain for sale of an interest in a Colombian pipeline of $22 million.

Chemical

In millions	2012		2011		2010
Segment Sales	$	4,580	$	4,815	$	4,016
Segment Earnings	$	720	$	861	$	438
Capital Expenditures	$	357	$	234	$	237

Chemical segment earnings were $720 million in 2012, compared to $861 million in 2011. The reduction was primarily the result of lower margins due to weaker economic conditions in Europe and Asia and increased competitive activity from these regions. The calcium chloride and potassium hydroxide businesses were also negatively impacted by a mild winter and drought conditions in the United States.

Chemical segment earnings were $861 million in 2011, compared to $438 million in 2010. The 2011 results reflected strong export sales and higher margins resulting from higher demand across most products.

The increase in the chemical capital expenditures was mostly due to the new chlor-alkali plant.

Midstream, Marketing and Other

In millions	2012		2011		2010
Segment Sales	$	1,399	$	1,447	$	1,471
Segment Earnings	$	439	$	448	$	472
Capital Expenditures	$	1,558	$	1,089	$	501

Midstream and marketing segment earnings in 2012 were $439 million, compared to $448 million in 2011. The 2012 results reflected lower gas processing earnings and improved marketing and trading performance.

Midstream and marketing segment earnings in 2011 were $448 million, compared to $472 million in 2010.  The 2011 results reflected lower gas processing margins, partially offset by improved marketing and trading performance.

The increase in the midstream and marketing capital expenditures was almost entirely due to the Al Hosn gas project.

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SIGNIFICANT ITEMS AFFECTING EARNINGS

The following table sets forth, for the years ended December 31, 2012, 2011 and 2010, significant transactions and events affecting Occidental’s earnings that vary widely and unpredictably in nature, timing and amount:

Significant Items Affecting Earnings
Benefit (Charge) (in millions)	2012			2011			2010
OIL AND GAS
Asset impairments and related items	$	(1,731	)	$	—		$	(275	)
Libya exploration write-off	—			(35		)	—
Gains on sale of Colombian pipeline interest	—			22			—
Foreign tax	—			(29		)	—
Total Oil and Gas	$	(1,731	)	$	(42	)	$	(275	)
CHEMICAL
No significant items affecting earnings	$	—		$	—		$	—
Total Chemical	$	—		$	—		$	—
MIDSTREAM AND MARKETING
No significant items affecting earnings	$	—		$	—		$	—
Total Midstream and Marketing	$	—		$	—		$	—
CORPORATE
Litigation reserves	$	(20	)	$	—		$	—
Premium on debt extinguishments	—			(163		)	—
State income tax charge	—			(33		)	—
Foreign tax credit carry-forwards	—			—			80
Tax effect of pre-tax adjustments	636			50			100
Discontinued operations, net of tax (a)	(37		)	131			(39		)
Total Corporate	$	579		$	(15	)	$	141

(a) The 2011 amount includes a $144 million after-tax gain from the sale of the Argentine operations.

TAXES

Deferred tax liabilities, net of deferred tax assets of $2.0 billion, were $5.8 billion at December 31, 2012. The current portion of the deferred tax assets of $250 million is included in other current assets. The deferred tax assets, net of allowances, 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	2012			2011			2010
EARNINGS
Oil and Gas	$	7,095		$	10,241		$	7,151
Chemical	720			861			438
Midstream and Marketing	439			448			472
Unallocated Corporate Items	(501		)	(709		)	(497		)
Pre-tax income	7,753			10,841			7,564
Income tax expense
Federal and State	694			1,795			1,087
Foreign	2,424			2,406			1,908
Total income tax expense	3,118			4,201			2,995
Income from continuing operations	$	4,635		$	6,640		$	4,569
Worldwide effective tax rate	40		%	39		%	40		%

Occidental’s 2012 worldwide tax rate was 40 percent, slightly higher than 2011 and comparable to 2010 due to higher proportionate foreign pre-tax income in 2012. The 2011 income tax expense included a net $21 million charge for out-of-period state income taxes. The 2010 income tax expense included an $80 million benefit related to foreign tax credit carryforwards.

A deferred tax liability has not been recognized for temporary differences related to unremitted earnings of certain consolidated foreign subsidiaries as it is Occidental’s intention, generally, to reinvest such earnings permanently. If the earnings of these foreign subsidiaries were not indefinitely reinvested, the additional deferred tax liability required would be immaterial, assuming utilization of available foreign tax credits.

CONSOLIDATED RESULTS OF OPERATIONS

Changes in components of Occidental's results of operations are discussed below:

Selected Revenue and Other Income Items

In millions	2012		2011		2010
Net sales	$	24,172	$	23,939	$	19,045
Interest, dividends and other income	$	81	$	180	$	112

The increase in net sales in 2012, compared to 2011, was due to higher oil volumes and prices, partially offset by lower gas and NGL prices and lower prices and volumes across most chemical products.

The increase in net sales in 2011, compared to 2010, was due to higher oil and NGL prices, higher oil and gas segment volumes and higher sales, including higher export sales, across most chemical products.

Price and volume changes in the oil and gas segment generally represent a substantially larger portion of the overall change in net sales than the chemical and midstream and marketing segments.

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Selected Expense Items

In millions	2012		2011		2010
Cost of sales (a)	$	7,844	$	7,385	$	6,112
Selling, general and administrative and other operating expenses	$	1,602	$	1,523	$	1,396
Depreciation, depletion and amortization	$	4,511	$	3,591	$	3,153
Taxes other than on income	$	680	$	605	$	484
Exploration expense	$	345	$	258	$	262
Asset impairments and related items	$	1,751	$	—	$	275
Interest and debt expense, net	$	130	$	298	$	116

(a) Excludes DD&A of $4,504 million in 2012, $3,584 million in 2011 and $3,145 million in 2010.

Cost of sales increased in 2012, compared to 2011, due to higher oil and gas volumes and operating costs, mostly resulting from higher maintenance activity and field support costs, partially offset by lower feedstock and energy costs in the chemical segment.

Cost of sales increased in 2011, compared to 2010, due to higher oil and gas volumes, higher oil and gas operating costs, mostly resulting from higher workover and well maintenance activity and higher feedstock costs in the chemical segment.

Selling, general and administrative and other operating expenses increased in 2012 due to higher headcount, partially offset by lower equity compensation expense and the Colombia net worth tax which increased the 2011 costs.

Selling, general and administrative and other operating expenses increased in 2011 due to higher headcount and environmental remediation expense and the Colombia net worth tax.

DD&A increased in each year from 2010 to 2012, generally due to higher DD&A rates and volumes in the oil and gas segment. The DD&A rate is expected to further increase in 2013.

Taxes other than on income increased in each year from 2010 to 2012, due to higher domestic oil volumes and prices and higher domestic ad valorem taxes resulting from higher property values.

Asset impairments and related items in 2012 were almost all in Midcontinent, over 90 percent of which were related to natural gas properties that were acquired more than four years ago on average when gas prices were over $6 per Mcf.

Asset impairments and related items in 2010 predominately related to gas properties in the Rocky Mountain region.

Interest and debt expense, net, in 2011, included the $163 million early debt extinguishment charge recorded in the first quarter of 2011.

Selected Other Items

Income/(expense) (in millions)	2012			2011			2010
Provision for income taxes	$	(3,118	)	$	(4,201	)	$	(2,995	)
Income from equity investments	$	363		$	382		$	277
Discontinued operations, net	$	(37	)	$	131		$	(39	)
Net income attributable to noncontrolling interest	$	—		$	—		$	72

Provision for income taxes decreased in 2012, compared to 2011, due to lower pre-tax income, partially offset by a slightly higher effective tax rate. The higher tax rate was due to higher proportional foreign pre-tax income in 2012, compared to 2011.

Provision for income taxes increased in 2011, compared to 2010, due to higher pre-tax income, partially offset by a slightly lower effective tax rate. The lower tax rate was due to higher proportional domestic pre-tax income in 2011, compared to 2010.

Income from equity investment in 2012 was comparable to 2011.

Income from equity investments increased in 2011, compared to 2010, due to an additional investment in the Plains Pipeline in late 2010 and its higher earnings.

Discontinued operations, net, in 2011, included the $144 million after-tax gain recorded from the sale of the Argentine operations.

There was no net income attributable to noncontrolling interest in 2012 and 2011 due to the restructuring of Occidental’s Colombian operations to take a direct working interest in the related assets as of December 31, 2010.

CONSOLIDATED ANALYSIS OF FINANCIAL POSITION

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

Selected Balance Sheet Components

In millions	2012		2011
CURRENT ASSETS
Cash and cash equivalents	$	1,592	$	3,781
Trade receivables, net	4,916		5,395
Inventories	1,344		1,069
Other current assets	1,640		1,297
Total current assets	$	9,492	$	11,542
Investments in unconsolidated entities	$	1,894	$	2,072
Property, plant and equipment, net	$	52,064	$	45,684
Long-term receivables and other assets, net	$	760	$	746
CURRENT LIABILITIES
Current maturities of long-term debt	$	600	$	—
Accounts payable	4,708		5,304
Accrued liabilities	1,966		2,533
Domestic and foreign income taxes	16		110
Total current liabilities	$	7,290	$	7,947
Long-term debt, net	$	7,023	$	5,871
Deferred credits and other liabilities-income taxes	$	6,039	$	4,846
Deferred credits and other liabilities-other	$	3,810	$	3,760
Stockholders’ equity	$	40,048	$	37,620

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Assets

See "Liquidity and Capital Resources — Cash Flow Analysis" for discussion about the change in cash and cash equivalents.

The decrease in trade receivables, net, was due to lower oil and gas prices at the end of 2012, compared to the end of 2011. The increase in inventories was primarily due to higher volumes of oil in storage and materials and supplies held at the end of 2012, compared to the end of 2011. The increase in other current assets in 2012 resulted from an increase in tax receivables. The decrease in investments in unconsolidated entities was mostly due to higher distributions received in the current year. The increase in PP&E, net, was due to capital expenditures and acquisitions of oil and gas properties, partially offset by DD&A and asset impairments.

Liabilities and Stockholders' Equity

The increase in current maturities of long-term debt was due to debt maturing in 2013. The decrease in accounts payable reflected lower oil and gas prices in the marketing and trading operations during the fourth quarter of 2012 and lower oil and gas spending levels at the end of 2012, compared to the same periods in 2011. The decrease in accrued liabilities was mostly due to the acceleration of the fourth quarter 2012 dividend payment, which normally would have been accrued as of year end but paid in the first quarter of the following year. The increase in long-term debt, net, was due to the June 2012 issuance of $1.75 billion of senior unsecured notes, partially offset by debt maturities that became current at the end of 2012. The increase in deferred and other domestic and foreign income taxes was mainly due to accelerated tax depreciation of the capital expenditures in 2012. The increase in stockholders' equity reflected net income for 2012, partially offset by dividends and treasury stock purchases.

LIQUIDITY AND CAPITAL RESOURCES

At December 31, 2012, Occidental had approximately $1.6 billion in cash on hand, a substantial majority of which is held domestically. Income and cash flows are largely dependent on the oil and gas segment's prices and sales volumes. Occidental believes that cash on hand and cash generated from operations will be sufficient to fund its operating needs and planned capital expenditures, dividends and any debt payments.

Occidental has a bank credit facility (Credit Facility) with a $2.0 billion commitment expiring in 2016. No amounts have been drawn under this Credit Facility. Up to $1.0 billion 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 average annual facility fees of 0.08 percent in 2012 on the total commitment amounts of the Credit Facility.

The Credit Facility provides for the termination of loan commitments and requires immediate repayment of any outstanding amounts if certain events of default occur. The Credit Facility and other debt agreements do not contain

material adverse change clauses or debt ratings triggers that could restrict Occidental's ability to borrow or that would permit lenders to terminate their commitments or accelerate debt.

As of December 31, 2012, under the most restrictive covenants of its financing agreements, Occidental had substantial capacity for additional unsecured borrowings, the payment of cash dividends and other distributions on, or acquisitions of, Occidental stock.

Occidental has a shelf registration statement that facilitates future issuances of securities. In June 2012, Occidental issued $1.75 billion of debt which comprised $1.25 billion of 2.70-percent senior unsecured notes due 2023 and $500 million of 1.50-percent senior unsecured notes due 2018. Occidental received net proceeds of approximately $1.74 billion. Interest on the notes will be payable semi-annually in arrears in February and August for each series of notes.

Occidental, from time to time, may access and has accessed debt markets for general corporate purposes, including acquisitions.

Cash Flow Analysis

In millions	2012		2011		2010
Net cash provided by operating activities	$	11,312	$	12,281	$	9,566

Although net income decreased by $2.2 billion for the twelve months ended December 31, 2012, compared to the same period of 2011, net cash provided by operating activities only decreased by $1.0 billion for this period. Compared to 2011, net income in 2012 included much larger non-cash charges, which reduced net income but not cash provided by operating activities. These non-cash charges mainly comprised asset impairments and higher DD&A. Working capital changes in 2012 further reduced cash flow from operations by approximately $0.8 billion, compared to 2011.

Additionally, operating cash flows in 2012, compared to 2011, reflected lower domestic gas and worldwide NGL prices, by 35 percent and 19 percent, respectively, and higher maintenance activity and field support costs, partially offset by higher domestic oil volumes and 2-percent higher worldwide oil prices. The positive cash-flow impact of the oil price change was more than offset by the negative effect of significant declines in gas and NGL prices. The decrease in operating cash flows in 2012, compared to 2011, also reflected lower chemical margins, primarily due to weaker economic conditions in Europe and Asia.

Other cost elements, such as labor costs and overhead, are not significant drivers of changes in cash flow because they are relatively stable within a narrow range over the short to intermediate term. Changes in these costs had a much smaller effect on cash flow than the changes in oil prices and volumes and gas and NGL prices.

The most important sources of the increase in operating cash flow in 2011, compared to 2010, were higher worldwide oil and NGL prices and volumes. In 2011,

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compared to 2010, Occidental’s global realized oil and NGL prices increased 30 percent and 23 percent, respectively. In 2011, Occidental’s oil and NGL production accounted for 71 percent of its total net sales. Increases in field support, workover and well maintenance costs in 2011, compared to 2010, partially offset the increases in prices and volumes. The increase in operating cash flows in 2011, compared to 2010, also reflected high chemical product prices and margins for most products.

The impact of the chemical and the midstream and marketing segments on overall cash flows is generally less significant than the impact of the oil and gas segment because the chemical and midstream and marketing segments are significantly smaller.

Other non-cash charges to income in 2012, 2011 and 2010 included charges for stock-based compensation plans and asset retirement obligation accruals.

Operating cash flows for discontinued operations include the Argentine operations through the date they were sold in February 2011.

In millions	2012			2011			2010
Capital expenditures
Oil and Gas	$	(8,220	)	$	(6,145	)	$	(3,166	)
Chemical	(357		)	(234		)	(237		)
Midstream and Marketing	(1,558		)	(1,089		)	(501		)
Corporate	(91		)	(50		)	(36		)
Total	(10,226		)	(7,518		)	(3,940		)
Other investing activities, net	(2,429		)	(4,955		)	(4,940		)
Net cash used by investing activities – continuing operations	(12,655		)	(12,473		)	(8,880		)
Investing cash flow from discontinued operations	—			2,570			(415		)
Net cash used by investing activities	$	(12,655	)	$	(9,903	)	$	(9,295	)

The increase in capital expenditures of $2.7 billion from 2011 to 2012 was mainly due to the $2.1 billion increase in oil and gas expenditures, a majority of which was in domestic properties, such as Permian and California, as well as increases throughout the Middle East. Occidental’s United States average operated-rig activity increased 25 percent from 51 rigs in 2011 to 64 rigs in 2012. The rig count was 41 at the end of 2012. The increase in the midstream and marketing capital expenditures was almost entirely due to the Al Hosn gas project.

Occidental’s capital spending is expected to decrease in 2013 to approximately $9.6 billion and will be focused on increasing oil production and ensuring Occidental's returns remain well above its costs of capital given current prices and the cost environment. The reduction in capital will come entirely from the oil and gas segment, almost all of which will be in Occidental's domestic operations. Occidental expects that a meaningful portion of the capital reduction will come from efficiencies in its drilling program. During the fourth quarter of 2012, Occidental embarked on an efficiency program that, among other things, targeted a 15-percent reduction in its drilling costs. Through the end of 2012 and early 2013, Occidental believes that it has already achieved about half of the targeted savings with further improvements expected during the remainder of 2013. Occidental believes it will be able to grow oil

production while reducing capital expenditures because it expects much of the capital reduction to come from efficiencies and not reduced activity. It expects only a modest impact on natural gas and NGL production from reduced gas drilling. The midstream and marketing segment capital spending will increase mainly for the BridgeTex pipeline. The 2013 capital program is expected to be approximately 75 percent in oil and gas, 11 percent in the Al Hosn gas project, 9 percent in domestic midstream and marketing and the remainder in the chemical segment.

Occidental expects to spend about 25 percent of its total capital expenditures on projects that will begin contributing to its earnings and cash flow over the next several years. These projects include the Al Hosn gas project, the BridgeTex pipeline, expansion of gas and CO₂ processing plants and a new chlor-alkali plant in the chemical business. As of December 31, 2012, the accumulated balance of such project costs that will contribute to earnings in future years, excluding costs of undeveloped acreage, was approximately $3.1 billion. Occidental expects this balance to grow by the end of 2013 before these investments start generating returns in 2014.

The 2012 other investing activities, net amount included $2.5 billion in cash payments for the acquisitions of businesses and assets, largely consisting of various interests in domestic oil and gas properties in the Permian Basin, the Williston Basin, California and South Texas. Also included in 2012 investing activities was approximately $190 million of cash dividends received as investment returns.

The increase in capital expenditures of $3.6 billion from 2010 to 2011 was mainly due to the $3.0 billion increase in oil and gas expenditures, which reflected Occidental’s share of development costs in Oman and Bahrain, and higher spending in domestic properties in California, the Permian Basin, South Texas and the Williston Basin. Occidental’s United States operated rig activity increased 89 percent from 38 rigs at year-end 2010 to 72 rigs at year-end 2011.

The 2011 other investing activities, net amount included $4.9 billion in cash payments for the acquisitions of businesses and assets, including various interests in domestic oil and gas properties, in operated, producing and non-producing properties in California and the Permian and Williston Basins for approximately $2.4 billion, properties in South Texas for $1.8 billion and $0.5 billion for Occidental’s share of pre-acquisition development expenditures incurred by the Al Hosn gas project.

The 2010 other investing activities, net amount included $4.9 billion in cash payments for the acquisitions of businesses and assets, including acquisitions of various interests in domestic oil and gas properties, in operated, producing and non-producing properties in the Permian Basin, Midcontinent region and California, for approximately $2.5 billion, properties in North Dakota for approximately $1.4 billion, additional interests in Plains Pipeline for approximately $430 million and the remaining 50-percent interest in EHP for approximately $175 million, as well as foreign contract payments of approximately $225 million.

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Investing cash flow from discontinued operations included $2.6 billion of cash received from the sale of the Argentine operations in 2011, and capital expenditures of $310 million in 2010.

Commitments at December 31, 2012, for major fixed and determinable capital expenditures were approximately $2.2 billion, which will be due in 2013 and beyond.  Occidental expects to fund these commitments and capital expenditures with cash from operations.

In millions	2012			2011			2010
Net cash (used) provided by financing activities	$	(846	)	$	(1,175	)	$	1,083

The 2012 net cash used by financing activities included net proceeds of approximately $1.7 billion from the June 2012 issuance of senior unsecured notes. Common stock dividends paid increased by $0.7 billion to $2.1 billion in 2012, which included the accelerated payment of the fourth quarter dividend. In addition, purchases of treasury stock increased from $274 million in 2011 to $583 million.

The 2011 amount included net proceeds of approximately $2.1 billion from the August 2011 issuance of senior unsecured notes and financing cash flow use of $1.5 billion to retire other long-term debt. Common stock dividends paid increased from $1.1 billion in 2010 to $1.4 billion in 2011. In addition, purchases of treasury stock increased from $67 million in 2010 to $274 million in 2011.

The 2010 amount included net proceeds of approximately $2.6 billion from the issuance of senior unsecured notes and financing cash flow use of $311 million to retire other long-term debt.

OFF-BALANCE-SHEET ARRANGEMENTS

The following is a description of the business purpose and nature of Occidental's off-balance-sheet arrangements.

Guarantees

Occidental has guaranteed certain equity investees' debt and has entered into various other guarantees including performance bonds, letters of credit, indemnities and commitments provided by Occidental to third parties, mainly to provide assurance that OPC or its subsidiaries and affiliates will meet their various obligations (guarantees). As of December 31, 2012, Occidental’s guarantees were not material and a substantial majority consisted of limited recourse guarantees on approximately $370 million of Dolphin’s debt, for which the fair value was immaterial.

See "Oil and Gas Segment — Business Review — Qatar" and “Segment Results of Operations” for further information about Dolphin.

Leases

Occidental has entered into various operating lease agreements, mainly for transportation equipment, power plants, machinery, terminals, storage facilities, land and office space. Occidental leases assets when leasing offers greater operating flexibility. Lease payments are generally expensed as part of cost of sales and selling, general and administrative expenses. For more information, see "Contractual Obligations."

CONTRACTUAL OBLIGATIONS

The table below summarizes and cross-references Occidental’s contractual obligations. This summary indicates on- and off-balance-sheet obligations as of December 31, 2012.

Contractual Obligations (in millions)			Payments Due by Year
	Total		2013		2014 and 2015		2016 and 2017		2018 and thereafter
On-Balance Sheet
Long-term debt (Note 5) (a)	$	7,654	$	600	$	—	$	2,700	$	4,354
Other long-term liabilities (b)	2,202		276		477		200		1,249
Off-Balance Sheet
Operating leases (Note 6)	976		158		211		147		460
Purchase obligations (c)	8,723		2,745		2,065		923		2,990
Total	$	19,555	$	3,779	$	2,753	$	3,970	$	9,053

(a) Excludes unamortized debt discount and interest on the debt.  As of December 31, 2012, interest on long-term debt totaling $1.7 billion is payable in the following years (in millions): 2013 - $230, 2014 and 2015 - $443, 2016 and 2017 - $341, 2018 and thereafter - $658.

(b) Includes obligations under postretirement benefit and deferred compensation plans, as well as certain accrued liabilities.

(c) Amounts include payments which will become due under long-term agreements to purchase goods and services used in the normal course of business to secure terminal and pipeline capacity, drilling rigs and services, CO_2, electrical power, steam and certain chemical raw materials. Amounts exclude certain oil purchase obligations related to marketing and trading activities for which there are no minimum purchase requirements.  Long-term purchase contracts are discounted at a 3.0-percent discount rate.

Delivery Commitments

Occidental has made commitments to certain refineries and other buyers to deliver a portion of its oil, gas and NGL production. The total amount contracted to be delivered, a substantial majority of which is in the United States, is approximately 65 million barrels of oil through 2019, 73 billion cubic feet of gas through 2016 and 3 million barrels of NGLs through 2013. The price for these deliveries is set at the time of delivery of the product. Occidental has significantly more production capacity than the amounts committed and none of the commitments in any given year are material. In addition, Occidental has the ability to secure additional volumes in the case of a shortfall.

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LAWSUITS, CLAIMS AND CONTINGENCIES

OPC or certain of its subsidiaries are involved, in the normal course of business, in lawsuits, claims and other legal proceedings that seek, among other things, compensation for alleged personal injury, breach of contract, property damage or other losses, punitive damages, civil penalties, or injunctive or declaratory relief. OPC or certain of its subsidiaries also are involved 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, civil penalties and injunctive relief. Usually OPC or such subsidiaries are among many companies in these environmental proceedings and have to date been successful in sharing response costs with other financially sound companies. Further, some lawsuits, claims and legal proceedings involve acquired assets with respect to which third parties retain liability or indemnify Occidental for conditions that existed prior to purchase.

Occidental accrues reserves for currently outstanding lawsuits, claims and proceedings when it is probable that a liability has been incurred and the liability can be reasonably estimated. Occidental has disclosed its reserve balances for environmental matters. Reserve balances for other matters as of December 31, 2012 and 2011, were not material to Occidental's consolidated balance sheets. Occidental also evaluates the amount of reasonably possible losses that it could incur as a result of the matters mentioned above. Occidental has disclosed its range of reasonably possible additional losses for sites where it is a participant in environmental remediation. Occidental believes that other reasonably possible losses that it could incur in excess of reserves accrued on the balance sheet would not be material to its consolidated financial position or results of operations. Environmental matters are further discussed under the caption "Environmental Liabilities and Expenditures" below.

On October 5, 2012, an Arbitral Tribunal of the International Centre for Settlement of Investment Disputes (ICSID), an agency of the World Bank, found that Ecuador violated the United States - Ecuador Bilateral Investment Treaty in 2006 when it terminated Occidental’s Block 15 concession. The Tribunal ordered Ecuador to pay $1.77 billion, plus interest, in damages. Ecuador has filed an application asking ICSID to annul the damage award; it could take over a year for ICSID to rule on Ecuador’s application for annulment. Pursuant to a 2000 Farmout Agreement, Andes Petroleum is entitled to 40% of any net amount which Occidental recovers from Ecuador in this ICSID proceeding. The effect, if any, on the financial statements will be recognized upon final resolution of this matter.

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. Although taxable years through 2009 for United States federal income tax purposes have been audited by the United States Internal Revenue Service (IRS) pursuant to

its Compliance Assurance Program, subsequent taxable years are currently under review. Additionally, in December 2012, Occidental filed United States federal refund claims for tax years 2008 and 2009 which are subject to IRS review. Taxable years from 2000 through the current year remain subject to examination by foreign and state government tax authorities in certain jurisdictions. In certain of these jurisdictions, tax authorities are in various stages of auditing Occidental's income taxes. During the course of tax audits, disputes have arisen and other disputes may arise as to facts and matters of law. Occidental believes that the resolution of outstanding tax matters would not have a material adverse effect on its consolidated financial position or results of operations.

OPC, its subsidiaries or both have indemnified various parties against specified liabilities 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, 2012, Occidental is not aware of circumstances that it believes would reasonably be expected to lead to indemnity claims that would result in payments materially in excess of reserves.

ENVIRONMENTAL LIABILITIES AND EXPENDITURES

Occidental’s operations are subject to stringent federal, state, local and foreign laws and regulations related to improving or maintaining environmental quality. Occidental’s environmental compliance costs have generally increased over time and are expected to rise in the future. Occidental factors environmental expenditures for its operations into its business planning process as an integral part of producing quality products responsive to market demand.

Environmental Remediation

The laws that require or address environmental remediation, including CERCLA and similar federal, state, local and foreign laws, may apply retroactively and regardless of fault, the legality of the original activities or the current ownership or control of sites. OPC or certain of its subsidiaries participate in or actively monitor a range of remedial activities and government or private proceedings under these laws with respect to alleged past practices at operating, closed and third-party sites. Remedial activities may include one or more of the following: investigation involving sampling, modeling, risk assessment or monitoring; cleanup measures including removal, treatment or disposal; or operation and maintenance of remedial systems. The environmental proceedings seek funding or performance of remediation and, in some cases, compensation for alleged property damage, punitive damages, civil penalties, injunctive relief and government oversight costs.

As of December 31, 2012, Occidental participated in or monitored remedial activities or proceedings at 161 sites. The following table presents Occidental’s environmental remediation reserves as of December 31, 2012, 2011 and 2010, grouped as environmental remediation sites listed or proposed for listing by the U.S. Environmental Protection

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Agency on the CERCLA National Priorities List (NPL sites) and three categories of non-NPL sites — third-party sites, Occidental-operated sites and closed or non-operated Occidental sites.

$ amounts in millions	2012			2011			2010
	# of Sites	Reserve Balance		# of Sites	Reserve Balance		# of Sites	Reserve Balance
NPL sites	35	$	54	36	$	63	38	$	56
Third-party sites	75	84		73	88		83	91
Occidental-operated sites	22	123		22	120		20	122
Closed or non-operated Occidental sites	29	83		29	89		29	97
Total	161	$	344	160	$	360	170	$	366

As of December 31, 2012, Occidental’s environmental reserves exceeded $10 million each at 12 of the 161 sites described above, and 112 of the sites had reserves from $0 to $1 million each.

As of December 31, 2012, two landfills in western New York owned by Occidental accounted for 73 percent of its reserves associated with NPL sites. In connection with a 1986 acquisition, Maxus Energy Corporation has retained the liability and indemnified Occidental for 14 of the remaining NPL sites.

As of December 31, 2012, Maxus has also retained the liability and indemnified Occidental for 8 of the 75 third-party sites. Two of the remaining 67 third-party sites — a former copper mining and smelting operation in Tennessee and a containment and removal project in Tennessee — accounted for 43 percent of Occidental’s reserves associated with these sites.

Five sites — chemical plants in Kansas, Louisiana, Texas and New York and a group of oil and gas properties in the southwestern United States — accounted for 70 percent of the reserves associated with the Occidental-operated sites.

Three other sites — former chemical plants in Tennessee and Delaware and a closed coal mine in Pennsylvania — accounted for 55 percent of the reserves associated with closed or non-operated Occidental sites.

Environmental reserves vary over time depending on factors such as acquisitions or dispositions, identification of additional sites and remedy selection and implementation. The following table presents environmental reserve activity for the past three years:

In millions	2012			2011			2010
Balance — Beginning of Year	$	360		$	366		$	403
Remediation expenses and interest accretion	56			53			26
Changes from acquisitions/dispositions	—			14			3
Payments	(72		)	(73		)	(66		)
Balance — End of Year	$	344		$	360		$	366

Based on current estimates, Occidental expects to expend funds corresponding to approximately half of the current environmental reserves at the sites described above over the next four years and the balance at these

sites over the subsequent 10 or more years. Occidental believes its range of reasonably possible additional losses beyond those liabilities recorded for environmental remediation at these sites could be up to $375 million. See "Critical Accounting Policies and Estimates — Environmental Liabilities and Expenditures" for additional information.

Occidental’s environmental costs, some of which include estimates, are presented below for each segment for each of the years ended December 31:

In millions	2012		2011		2010
Operating Expenses
Oil and Gas	$	160	$	158	$	108
Chemical	70		68		72
Midstream and Marketing	20		21		13
	$	250	$	247	$	193
Capital Expenditures
Oil and Gas	$	122	$	110	$	72
Chemical	18		15		19
Midstream and Marketing	12		15		13
	$	152	$	140	$	104
Remediation Expenses
Corporate	$	56	$	52	$	25

Operating expenses are incurred on a continual basis. Capital expenditures relate to longer-lived improvements in currently operating properties. Remediation expenses relate to existing conditions from past operations.

Occidental presently estimates capital expenditures for environmental compliance of approximately $130 million for 2013.

FOREIGN INVESTMENTS

Many of Occidental’s assets are located outside North America. At December 31, 2012, the carrying value of Occidental’s assets in countries outside North America aggregated approximately $12.3 billion, or approximately 19 percent of Occidental’s total assets at that date. Of such assets, approximately $10.6 billion are located in the Middle East/North Africa and approximately $1.6 billion are located in Latin America. For the year ended December 31, 2012, net sales outside North America totaled $8.8 billion, or approximately 36 percent of total net sales.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The process of preparing financial statements in accordance with generally accepted accounting principles requires Occidental's management to make informed estimates and judgments regarding certain items and transactions. Changes in facts and circumstances or discovery of new information may result in revised estimates and judgments, and actual results may differ from these estimates upon settlement but generally not by material amounts. There has been no material change to Occidental's critical accounting policies over the past three years. The selection and development of these policies and estimates have been discussed with the Audit Committee of the Board of Directors. Occidental considers the following to be its most critical accounting policies and estimates that involve management's judgment.

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Oil and Gas Properties

The carrying value of Occidental’s property, plant and equipment (PP&E) represents the cost incurred to acquire or develop the asset, including any asset retirement obligations and capitalized interest, net of accumulated depreciation, depletion and amortization (DD&A) and net of any impairment charges. For assets acquired, PP&E cost is based on fair values at the acquisition date. Asset retirement obligations and interest costs incurred in connection with qualifying capital expenditures are capitalized and amortized over the lives of the related assets.

Occidental uses the successful efforts method to account for its oil and gas properties. Under this method, Occidental capitalizes costs of acquiring properties, costs of drilling successful exploration wells and development costs. The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. If proved reserves have been found, the costs of exploratory wells remain capitalized. Otherwise, Occidental charges the costs of the related wells 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 generally expenses the costs of such exploratory wells if a determination of proved reserves has not been made within a 12-month period after drilling is complete.

Occidental expenses annual lease rentals and geological, geophysical and seismic costs as incurred.

Occidental expenses the costs of injectants used in production.

Occidental determines depreciation and depletion of oil and gas producing properties by the unit-of-production method. It amortizes acquisition costs over total proved reserves and capitalized development and successful exploration costs over proved developed reserves.

Proved oil and gas reserves (as defined in the Securities and Exchange Commission's Regulation S-X, Rule 4-10(a)) are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Occidental has no proved oil and gas reserves for which the determination of economic producibility is subject to the completion of major additional capital expenditures.

Several factors could change Occidental’s proved oil and gas reserves. For example, Occidental receives a share of production from PSCs to recover its costs and generally 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 cases, particularly with long-lived properties, lower product prices

may lead to a situation where production of a portion of proved reserves becomes uneconomical. For such properties, higher product prices typically result in additional reserves becoming economical. 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 proved reserves. Additional factors that could result in a change of proved reserves include production decline rates and operating performance differing from those estimated when the proved reserves were initially recorded. In 2012, revisions of previous estimates provided a net 183 million BOE reduction to proved reserves, which amounted to less than 6 percent of Occidental's total reserves as of December 31, 2012.

In 2012, revisions related to price for the company as a whole were negative. A substantial majority of such revisions related to Occidental's domestic gas reserves and resulted from lower domestic gas prices. These lower prices and the resulting changes in Occidental's plans for drilling on gas properties constituted a majority of its total revisions. To the extent gas prices recover in the future, a portion of these reserves will be reinstated. If natural gas prices decrease further for an extended period, domestic gas reserves could experience additional negative price revisions.

The most significant financial statement effect from a change in Occidental's oil and gas reserves would be to the DD&A rate. For example, a 5-percent increase or decrease in the amount of oil and gas reserves would change the DD&A rate by approximately $0.80 per barrel, which would increase or decrease pre-tax income by approximately $225 million annually at current production rates. 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, 2012, the net capitalized costs attributable to unproved properties were $4.8 billion. The unproved amounts are not subject to DD&A until they are classified as proved properties. As exploration and development work progresses, if reserves on these properties are proved, capitalized costs attributable to the properties become subject to DD&A. If the exploration and development work were to be unsuccessful, or management's plans changed with respect to these properties, as a result of economic, operating or contractual conditions, the capitalized costs of the related properties would be expensed. The timing of any writedowns of these unproved properties, if warranted, depends upon management's plans, the nature, timing and extent of future exploration and development activities and their results. Occidental believes its current plans and exploration and development efforts will allow it to realize its unproved property balance.

Additionally, Occidental performs impairment tests with respect to its proved properties generally when prices decline other than temporarily, reserve estimates change significantly or other significant events occur that may

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impact its ability to realize the recorded asset amounts. Impairment tests incorporate a number of assumptions involving expectations of future cash flows, which can change significantly over time. These assumptions include estimates of future product prices, which Occidental bases on forward price curves and, when applicable, contractual prices, estimates of oil and gas reserves and estimates of future expected operating and development costs.

In the fourth quarter of 2012, impairment charges totaling $1.7 billion pre-tax were taken on certain proved and unproved properties. Almost all of the charges were for certain properties in Midcontinent, over 90 percent of which were related to natural gas properties that were acquired more than four years ago on average when gas prices were more than $6 per Mcf. These properties were impacted by persistently low natural gas prices in the United States changing management's development plans and negative reserve revisions due to recent well performance. Any impairment loss would be calculated as the excess of the asset's net book value over its estimated fair value. Any further sustained declines in gas prices as well as significant sustained reductions in the prices of other products may result in additional impairments in the future.

Chemical Assets

Occidental's chemical assets are depreciated using either the unit-of-production or the straight-line method, based upon the estimated useful lives of the facilities. The estimated useful lives of Occidental’s chemical assets, which range from three years to 50 years, are also used for impairment tests. The estimated useful lives 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. Such expenditures consist of ongoing routine repairs and maintenance, as well as planned major maintenance activities (PMMA). Ongoing routine repairs and maintenance expenditures are expensed as incurred. PMMA costs are capitalized and amortized over the period until the next planned overhaul. Additionally, Occidental incurs capital expenditures that extend the remaining useful lives of existing assets, increase their capacity or operating efficiency beyond the original specification or add value through modification for a different use. These capital expenditures are not considered in the initial determination of the useful lives of these assets at the time they are placed into service. The resulting revision, if any, of the asset’s estimated useful life is measured and accounted for prospectively.

Without these continued expenditures, the useful lives of these assets could decrease significantly. Other factors that could change the estimated useful lives of Occidental’s chemical assets include sustained higher or lower product prices, which are particularly affected by both domestic and foreign competition, demand, feedstock costs, energy prices, environmental regulations and technological changes.

Occidental performs impairment tests on its chemical assets whenever events or changes in circumstances lead to a reduction in the estimated useful lives or estimated future cash flows that would indicate that the carrying amount may not be recoverable, or when management’s plans change with respect to those assets. Any impairment loss would be calculated as the excess of the asset's net book value over its estimated fair value.

Occidental's net PP&E for the chemical segment is approximately $2.6 billion and its depreciation expense for 2013 is expected to be approximately $300 million. The most significant financial statement impact of a decrease in the estimated useful lives of Occidental's chemical plants 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 $45 million per year.

Midstream, Marketing and Other Assets

Derivatives are carried at fair value and on a net basis when a legal right of offset exists with the same counterparty. Occidental applies hedge accounting when transactions meet specified criteria for cash-flow hedge treatment and management elects and documents such treatment. Otherwise, any fair value gains or losses are recognized in earnings in the current period. For cash-flow hedges, the gain or loss on the effective portion of the derivative is reported as a component of other comprehensive income (OCI) with an offsetting adjustment to the basis of the item being hedged. Realized gains or losses from cash-flow hedges, and any ineffective portion, are recorded as a component of net sales in the consolidated statements of income. Ineffectiveness is primarily created by a basis difference between the hedged item and the hedging instrument due to location, quality or grade of the physical commodity transactions. Gains and losses from derivative instruments are reported net in the consolidated statements of income. There were no fair value hedges as of and during the year ended December 31, 2012.

A hedge is regarded as highly effective such that it 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 will be offset by 80 to 125 percent of the changes in the fair value or cash flows, respectively, of the hedging instrument. In the case of hedging a forecast transaction, the transaction must be 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 hedged item matures or is sold or repaid; or when a forecast transaction is no longer deemed probable.

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Occidental's midstream and marketing PP&E is depreciated over the estimated useful lives of the assets, using either the unit-of-production or straight-line method. Occidental performs impairment tests on its midstream and marketing 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. Any impairment loss would be calculated as the excess of the asset's net book value over its estimated fair value.

Fair Value Measurements

Occidental has categorized its assets and liabilities that are measured at fair value in a three-level fair value hierarchy, based on the inputs to the valuation techniques: Level 1 – using quoted prices in active markets for identical assets or liabilities; Level 2 – using observable inputs other than quoted prices for identical assets or liabilities; and Level 3 – using unobservable inputs.  Transfers between levels, if any, are recognized at the end of each reporting period.

Fair Values - Recurring

Occidental primarily applies the market approach for recurring fair value measurements, maximizes its use of observable inputs and minimizes its use of unobservable inputs. Occidental utilizes the mid-point price between bid and ask prices for valuing the majority of its assets and liabilities measured and reported at fair value. In addition to using market data, Occidental makes assumptions in valuing its assets and liabilities, including assumptions about the risks inherent in the inputs to the valuation technique. For assets and liabilities carried at fair value, Occidental measures fair value using the following methods:

Ø Commodity derivatives – Occidental values exchange-cleared commodity derivatives using closing prices provided by the exchange as of the balance sheet date. These derivatives are classified as Level 1. Over-the-Counter (OTC) bilateral financial commodity contracts, foreign exchange contracts, options and physical commodity forward purchase and sale contracts are generally valued using quotations provided by brokers or industry-standard models that consider various inputs, including quoted forward prices for commodities, time value, volatility factors, credit risk and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument, and can be derived from observable data or are supported by observable prices at which transactions are executed in the marketplace. Occidental generally classifies these measurements as Level 2.

Ø Embedded commodity derivatives – Occidental values embedded commodity derivatives based on a market approach that considers various assumptions, including quoted forward commodity prices and market yield curves. The assumptions used include inputs that are observable and unobservable in the marketplace, and the fair value is designated as Level 3 within the valuation hierarchy.

Occidental generally uses an income approach to measure fair value when there is not a market-observable price for an identical or similar asset or liability.  This approach utilizes management's judgments regarding expectations of projected cash flows, and discounts those cash flows using a risk-adjusted discount rate.

Environmental Liabilities and Expenditures

Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Occidental records environmental reserves for estimated remediation costs that relate to existing conditions from past operations when environmental remediation efforts are probable and the costs can be reasonably estimated. In determining the reserves and the range of reasonably possible additional losses, Occidental refers to currently available information, including relevant past experience, remedial objectives, available technologies, applicable laws and regulations and cost-sharing arrangements. Occidental bases environmental reserves on management’s estimate of the most likely cost to be incurred, using the most cost-effective technology reasonably expected to achieve the remedial objective. Occidental periodically reviews reserves and adjusts them as new information becomes available. Occidental records environmental reserves on a discounted basis when it deems the aggregate amount and timing of cash payments to be reliably determinable at the time the reserves are established. The reserve methodology with respect to discounting for a specific site is not modified once it is established. The amount of discounted environmental reserves is insignificant. Occidental generally records reimbursements or recoveries of environmental remediation costs in income when received, or when receipt of recovery is highly probable. As of December 31, 2012, 2011 and 2010, Occidental did not have any accruals for reimbursements or recoveries.

Many factors could affect Occidental’s future remediation costs and result in adjustments to its environmental reserves and range of reasonably possible additional losses. The most significant are: (1) cost estimates for remedial activities may be inaccurate; (2) the length of time, type or amount of remediation necessary to achieve the remedial objective may change due to factors such as site conditions, the ability to identify and control contaminant sources or the discovery of additional contamination; (3) a regulatory agency may ultimately reject or modify Occidental’s proposed remedial plan; (4) improved or alternative remediation technologies may change remediation costs; (5) laws and regulations may change remediation requirements or affect cost sharing or allocation of liability; and (6) changes in allocation or cost-sharing arrangements.

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Certain sites involve multiple parties with various cost-sharing arrangements, which fall into the following three categories: (1) environmental proceedings that result in a negotiated or prescribed allocation of remediation costs among Occidental and other alleged potentially responsible parties; (2) oil and gas ventures in which each participant pays its proportionate share of remediation costs reflecting its working interest; or (3) contractual arrangements, typically relating to purchases and sales of properties, in which the parties to the transaction agree to methods of allocating remediation costs. In these circumstances, Occidental evaluates the financial viability of other parties with whom it is alleged to be jointly liable, the degree of their commitment to participate and the consequences to Occidental of their failure to participate when estimating Occidental's ultimate share of liability. Occidental records reserves at its expected net cost of remedial activities and, based on these factors, believes that it will not be required to assume a share of liability of such other potentially responsible parties in an amount materially above amounts reserved.

In addition to the costs of investigations and cleanup measures, which often take in excess of 10 years at NPL sites, Occidental’s reserves include management’s estimates of the costs to operate and maintain remedial systems. If remedial systems are modified over time in response to significant changes in site-specific data, laws, regulations, technologies or engineering estimates, Occidental reviews and adjusts its reserves accordingly.

If Occidental were to adjust the environmental reserve balance based on the factors described above, the amount of the increase or decrease would be recognized in earnings. For example, if the reserve balance were reduced by 10 percent, Occidental would record a pre-tax gain of $34 million. If the reserve balance were increased by 10 percent, Occidental would record an additional remediation expense of $34 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.

Loss contingencies 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, or interpretations of, laws or regulations, changes in management’s plans or intentions, opinions regarding the outcome of legal proceedings, or other factors. See "Lawsuits, Claims and Other Contingencies" for additional information.

SIGNIFICANT ACCOUNTING AND DISCLOSURE CHANGES

Listed below are significant recently adopted accounting and disclosure changes.

Fair Value Measurements

Beginning in the quarter ended March 31, 2012, Occidental enhanced its fair value measurement application and disclosures as a result of adopting new requirements issued by the Financial Accounting Standards Board in May 2011. The new rules include revisions to the standards for the use of fair value measurements and additional disclosures for: (i) all transfers between Level 1 and Level 2 of the fair value hierarchy; (ii) Level 3 measurements; and (iii) hierarchy classifications used for assets and liabilities whose fair value is disclosed only in the footnotes. The new rules did not have a material impact on Occidental.

DERIVATIVE ACTIVITIES AND MARKET RISK

Commodity Price Risk

General

Occidental’s results are sensitive to fluctuations in oil, NGL and natural gas prices. Price changes at current global prices and levels of production affect Occidental’s pre-tax annual income by approximately $150 million for a $1 per barrel change in oil prices and $30 million for a $1 per barrel change in NGL prices. If domestic natural gas prices varied by $0.50 per Mcf, it would have an estimated annual effect on Occidental's pre-tax income of approximately $115 million. These price-change sensitivities include the impact of PSC and similar contract volume changes on income. If production levels change in the future, the sensitivity of Occidental’s results to oil and gas prices also will change. The marketing and trading results are also sensitive to price changes of oil, gas and, to a lesser degree, other commodities. These sensitivities are additionally dependent on marketing and trading volumes and cannot be predicted reliably.

Occidental’s results are also sensitive to fluctuations in chemical prices. A variation in chlorine and caustic soda prices of $10 per ton would have a pre-tax annual effect on income of approximately $10 million and $30 million, respectively. A variation in PVC prices of $0.01 per lb. would have a pre-tax annual effect on income of approximately $25 million. Historically, over time, product price changes have tracked raw material and feedstock product price changes, somewhat mitigating the effect of price changes on margins. According to Chemical Market Associates, Inc., December 2012 average contract prices were: chlorine—$255 per ton; caustic soda—$635 per ton; and PVC—$0.56 per lb.

Occidental uses derivative instruments, including a combination of short-term futures, forwards, options and swaps, to establish, as of the date of production, the price it receives and to improve realized prices for oil and gas. Occidental only occasionally hedges its oil and gas production and, when it does so, the volumes are usually insignificant. Additionally, Occidental’s Phibro trading unit engages in trading activities using derivatives for the

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purpose of generating profits mainly from market price changes of commodities. 

Risk Management

Occidental conducts its risk management activities for marketing and trading activities under the controls and governance of its risk control policy. The controls under this policy are implemented and enforced by certain members of management embedded in the marketing and trading operations in order to manage risk by providing an independent and separate evaluation and check. These members of management report to the Corporate Vice President and Treasurer. The President and Chief Executive Officer and risk committees comprising members of Occidental's senior corporate management also oversee these controls. Controls for these activities include limits on value at risk, limits on credit, limits on total notional trade value, segregation of duties, delegation of authority, daily price verifications, daily reporting to senior management of positions together with various risk measures and a number of other policy and procedural controls. Additionally, these operations maintain highly liquid positions, as a result of which the market risk typically can be neutralized on short notice.

Fair Value of Marketing and Trading Derivative Contracts

Occidental's marketing and trading derivative contracts are carried at fair value and result from third-party marketing and trading activities, sales of its production and activities to generate profits mainly from price changes in the commodities markets.

The following table shows the fair value of Occidental's derivatives (excluding collateral), segregated by maturity periods and by methodology of fair value estimation:

	Maturity Periods
Source of Fair Value Assets/(liabilities) (in millions)	2013			2014 and 2015			2016 and 2017		2018 and thereafter		Total
Prices actively quoted	$	9		$	(1	)	$	—	$	—	$	8
Prices provided by other external sources	(60		)	(27		)	1		—		(86		)
Total	$	(51	)	$	(28	)	$	1	$	—	$	(78	)

Note: Includes cash-flow hedges further discussed below.

Cash-Flow Hedges

Occidental entered into financial swap agreements in November 2012 for the sale of a portion of its natural gas production in California. These swap agreements hedge 50 million cubic feet of natural gas per day beginning in January 2013 through March 2014 and qualify as cash-flow hedges. The weighted-average strike price of these swaps is $4.30.

Through March 31, 2012, Occidental held financial swap agreements related to the sale of 50 million cubic feet per day of its existing natural gas production from the Rocky Mountain region of the United States that qualified as cash-flow hedges at a weighted-average strike price of $6.07.

Through 2011, Occidental held a series of collar agreements for 12,000 barrels of oil per day of its domestic production that qualified as cash-flow hedges at a

weighted-average strike price that ranged from $32.92 to $46.35.

Occidental’s marketing and trading operations store natural gas purchased from third parties at Occidental’s North American leased storage facilities. Derivative instruments are used to fix margins on the future sales of the stored volumes through March 31, 2013. As of December 31, 2012 and 2011, Occidental had approximately 20 billion cubic feet and 25 billion cubic feet of natural gas held in storage, respectively. As of December 31, 2012 and 2011, Occidental had cash-flow hedges for the forecast sale, to be settled by physical delivery, of approximately 20 billion cubic feet and 35 billion cubic feet of this stored natural gas, respectively.

As of December 31, 2012, the total fair value of cash-flow hedges, which was a net asset of $9 million, was included in the total fair value table in "Fair Value of Marketing and Trading Derivative Contracts" above.

Quantitative Information

Occidental uses value at risk to estimate the potential effects of changes in fair values of commodity-based and foreign currency derivatives and commodity contracts used in marketing and trading activities. This method determines the maximum potential negative short-term change in fair value with at least a 95-percent level of confidence. Additionally, Occidental uses trading limits, including, among others, limits on total notional trade value, and maintains liquid positions as a result of which market risk typically can be neutralized on short notice. As a result of these controls, Occidental has determined that the market risk of the marketing and trading activities is not reasonably likely to have a material adverse effect on it.  

Interest Rate Risk

General

Occidental's exposure to changes in interest rates is not expected to be material and relates to its variable-rate long-term debt obligations. As of December 31, 2012, variable-rate debt constituted approximately 1 percent of Occidental's total debt.

Tabular Presentation of Interest Rate Risk

The table below provides information about Occidental's debt obligations. Debt amounts represent principal payments by maturity date.

Year of Maturity (in millions of U.S. dollars)	U.S. Dollar Fixed-Rate Debt			U.S. Dollar Variable-Rate Debt			Grand Total (a)
2013	$	600		$	—		$	600
2014	—			—			—
2015	—			—			—
2016	1,450			—			1,450
2017	1,250			—			1,250
Thereafter	4,286			68			4,354
Total	$	7,586		$	68		$	7,654
Weighted-average interest rate	3.03		%	0.13		%	3.01		%
Fair Value	$	8,164		$	68		$	8,232

(a) Excludes unamortized debt discounts of $31 million.

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Credit Risk

Occidental's credit risk relates primarily to its derivative financial instruments and trade receivables. Occidental’s contracts are spread among a large number of counterparties. Creditworthiness is reviewed before doing business with a new counterparty and on an ongoing basis, and master netting arrangements are used when appropriate. Credit exposure for each customer is monitored for outstanding balances, current activity, and forward mark-to-market exposure.

A substantial portion of Occidental’s derivative transaction volume is executed through exchange-traded contracts, which are subject to nominal credit risk as a significant portion of these transactions is settled on a daily margin basis with select clearinghouses and brokers. Occidental executes the rest of its derivative transactions in the OTC market. Occidental is subject to counterparty credit risk to the extent the counterparty to the derivatives is unable to meet its settlement commitments. Occidental manages this credit risk by selecting counterparties that it believes to be financially strong, by spreading the credit risk among many such counterparties, by entering into master netting arrangements with the counterparties and by requiring collateral, as appropriate. Occidental actively monitors the creditworthiness of each counterparty and records valuation adjustments to reflect counterparty risk, if necessary.

Certain of Occidental's OTC derivative instruments contain credit-risk-contingent features, primarily tied to credit ratings for Occidental or its counterparties, which may affect the amount of collateral that each would need to post. As of December 31, 2012 and 2011, Occidental had a net liability of $34 million and $58 million, respectively, which are net of collateral posted of $64 million and $27 million, respectively. Occidental believes that if it had received a one-notch reduction in its credit ratings, it would not have resulted in a material change in its collateral-posting requirements as of December 31, 2012 and 2011.

As of December 31, 2012, the substantial majority of the credit exposures was with investment grade counterparties. Occidental believes its exposure to credit-related losses at December 31, 2012 was not material and losses associated with credit risk have been insignificant for all years presented.

Foreign Currency Risk

Occidental’s foreign operations have limited currency risk. Occidental manages its exposure primarily by balancing monetary assets and liabilities and limiting cash positions in foreign currencies to levels necessary for operating purposes. A vast majority of international oil sales are denominated in United States dollars. Additionally, all of Occidental’s consolidated foreign oil and gas subsidiaries have the United States dollar as the functional currency. As of December 31, 2012, the fair value of foreign currency derivatives used in the trading operations was immaterial. The effect of exchange rates on transactions in foreign currencies is included in periodic income.

SAFE HARBOR DISCUSSION REGARDING OUTLOOK AND OTHER FORWARD-LOOKING DATA

Portions of this report, including Items 1 and 2 (including the information appearing under the captions "Legal Proceedings," "Business and Properties — Competition and Sales and Marketing") and Items 7 and 7A (including "Management's Discussion and Analysis of Financial Condition and Results of Operations," including the information under the sub captions "Strategy," "Oil and Gas Segment — Operations, United Arab Emirates," "— Proved Reserves," "—Business Review" and "— Industry Outlook," "Chemical Segment — Business Review, Basic Chemicals," "— Industry Outlook," "Midstream, Marketing and Other Segment — Business Review, Gas Processing Plants and CO₂ Fields and Facilities" and "— Business Review, Pipeline Transportation," "— Industry Outlook," "Segment Results of Operations — Oil and Gas," "Taxes," "Consolidated Results of Operations — Selected Expense Items," "Liquidity and Capital Resources," "Lawsuits, Claims and Other Contingencies," "Environmental Liabilities and Expenditures," "Critical Accounting Policies and Estimates," and "Derivative Activities and Market Risk"), 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," "should," "could," "may," "might," "anticipate," "plan," "intend," "believe," "expect," "aim," "goal," "target," "objective," "likely" or similar expressions that convey the prospective nature of events or outcomes generally indicate 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. Factors that may cause Occidental’s results of operations and financial position to differ from expectations include items noted in Item 1A "Risk Factors," and elsewhere.

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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, 2012, 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, 2012, Occidental’s system of internal control over financial reporting is effective.

Occidental’s independent auditors, KPMG LLP, have issued an audit report on Occidental’s internal control over financial reporting.

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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, 2012 and 2011, and the related consolidated statements of income, comprehensive income, stockholders’ equity and cash flows for each of the years in the three-year period ended December 31, 2012. 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, 2012 and 2011, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2012, 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.

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, 2012, 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 26, 2013 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/ KPMG LLP

Los Angeles, California

February 26, 2013

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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, 2012, 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.

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.

In our opinion, Occidental Petroleum Corporation and its subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, 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, 2012 and 2011, and the related consolidated statements of income, comprehensive income, stockholders’ equity and cash flows for each of the years in the three-year period ended December 31, 2012, and our report dated February 26, 2013 expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

Los Angeles, California

February 26, 2013

39

Consolidated Balance Sheets	Occidental Petroleum Corporation and Subsidiaries
In millions

Assets at December 31,	2012			2011
CURRENT ASSETS
Cash and cash equivalents	$	1,592		$	3,781
Trade receivables, net of reserves of $16 in both 2012 and 2011	4,916			5,395
Inventories	1,344			1,069
Other current assets	1,640			1,297
Total current assets	9,492			11,542
INVESTMENTS IN UNCONSOLIDATED ENTITIES	1,894			2,072
PROPERTY, PLANT AND EQUIPMENT
Oil and gas segment	65,417			56,682
Chemical segment	6,054			5,715
Midstream, marketing and other segment	7,191			5,664
Corporate	1,434			1,310
	80,096			69,371
Accumulated depreciation, depletion and amortization	(28,032		)	(23,687		)
	52,064			45,684
LONG-TERM RECEIVABLES AND OTHER ASSETS, NET	760			746
TOTAL ASSETS	$	64,210		$	60,044

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

40

Consolidated Balance Sheets	Occidental Petroleum Corporation and Subsidiaries
In millions, except share and per-share amounts

Liabilities and Stockholders’ Equity at December 31,	2012			2011
CURRENT LIABILITIES
Current maturities of long-term debt	$	600		$	—
Accounts payable	4,708			5,304
Accrued liabilities	1,966			2,533
Domestic and foreign income taxes	16			110
Total current liabilities	7,290			7,947
LONG-TERM DEBT, NET	7,023			5,871
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred domestic and foreign income taxes	6,039			4,846
Other	3,810			3,760
	9,849			8,606
CONTINGENT LIABILITIES AND COMMITMENTS
STOCKHOLDERS' EQUITY
Common stock, $0.20 par value, authorized 1.1 billion shares, outstanding shares: 2012 — 888,801,436 and 2011 — 886,808,654	178			177
Treasury stock:  2012 — 83,287,187 shares and 2011 — 75,799,573 shares	(5,091		)	(4,502		)
Additional paid-in capital	7,441			7,286
Retained earnings	37,990			35,142
Accumulated other comprehensive loss	(502		)	(483		)
Total equity attributable to common stock	40,016			37,620
Noncontrolling interest	32			—
Total equity	40,048			37,620
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	64,210		$	60,044

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

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Consolidated Statements of Income	Occidental Petroleum Corporation and Subsidiaries
In millions, except per-share amounts

For the years ended December 31,	2012			2011			2010
REVENUES AND OTHER INCOME
Net sales	$	24,172		$	23,939		$	19,045
Interest, dividends and other income	81			180			112
	24,253			24,119			19,157
COSTS AND OTHER DEDUCTIONS
Cost of sales (excludes depreciation, depletion and amortization of $4,504 in 2012, $3,584 in 2011 and $3,145 in 2010)	7,844			7,385			6,112
Selling, general and administrative and other operating expenses	1,602			1,523			1,396
Depreciation, depletion and amortization	4,511			3,591			3,153
Asset impairments and related items	1,751			—			275
Taxes other than on income	680			605			484
Exploration expense	345			258			262
Interest and debt expense, net	130			298			116
	16,863			13,660			11,798
INCOME BEFORE INCOME TAXES AND OTHER ITEMS	7,390			10,459			7,359
Provision for domestic and foreign income taxes	(3,118		)	(4,201		)	(2,995		)
Income from equity investments	363			382			277
INCOME FROM CONTINUING OPERATIONS	4,635			6,640			4,641
Discontinued operations, net	(37		)	131			(39		)
NET INCOME	4,598			6,771			4,602
Less: Net income attributable to noncontrolling interest	—			—			(72		)
NET INCOME ATTRIBUTABLE TO COMMON STOCK	$	4,598		$	6,771		$	4,530
BASIC EARNINGS PER COMMON SHARE (attributable to common stock)
Income from continuing operations	$	5.72		$	8.16		$	5.62
Discontinued operations, net	(0.05		)	0.16			(0.05		)
BASIC EARNINGS PER COMMON SHARE	$	5.67		$	8.32		$	5.57
DILUTED EARNINGS PER COMMON SHARE (attributable to common stock)
Income from continuing operations	$	5.71		$	8.16		$	5.61
Discontinued operations, net	(0.04		)	0.16			(0.05		)
DILUTED EARNINGS PER COMMON SHARE	$	5.67		$	8.32		$	5.56
DIVIDENDS PER COMMON SHARE	$	2.16		$	1.84		$	1.47
The accompanying notes are an integral part of these consolidated financial statements.

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Consolidated Statements of Comprehensive Income	Occidental Petroleum Corporation and Subsidiaries
In millions

For the years ended December 31,	2012			2011			2010
Net income attributable to common stock	$	4,598		$	6,771		$	4,530
Other comprehensive income (loss) items:
Foreign currency translation (losses) gains	(25		)	(11		)	4
Unrealized gains on derivatives (a)	16			14			37
Pension and postretirement gains (losses) (b)	14			(60		)	(52		)
Reclassification to income of realized (gains) losses on derivatives (c)	(24		)	98			83
Other comprehensive income (loss), net of tax (d)	(19		)	41			72
Comprehensive income attributable to common stock	$	4,579		$	6,812		$	4,602

(a) Net of tax of $(9), $(7) and $(20) in 2012, 2011 and 2010, respectively.

(b) Net of tax of $(8), $34 and $30 in 2012, 2011 and 2010, respectively.

(c) Net of tax of $14, $(56) and $(47) in 2012, 2011 and 2010, respectively.

(d) There were no other comprehensive income (loss) items related to noncontrolling interests in 2012, 2011 and 2010.

Consolidated Statements of Stockholders' Equity
In millions
	Equity Attributable to Common Stock
	Common Stock		Treasury Stock			Additional Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interest				Total Equity
Balance, December 31, 2009	$	177	$	(4,161	)	$	7,127	$	26,534		$	(596	)	$	78			$	29,159
Net income	—		—			—		4,530			—			72				4,602
Other comprehensive income, net of tax	—		—			—		—			72			—				72
Dividends on common stock	—		—			—		(1,196		)	—			—				(1,196		)
Issuance of common stock and other, net	—		—			64		—			—			—				64
Noncontrolling interest distributions and other	—		—			—		—			—			(150		)	(a)	(150		)
Purchases of treasury stock	—		(67		)	—		—			—			—				(67		)
Balance, December 31, 2010	$	177	$	(4,228	)	$	7,191	$	29,868		$	(524	)	$	—			$	32,484
Net income	—		—			—		6,771			—			—				6,771
Other comprehensive income, net of tax	—		—			—		—			41			—				41
Dividends on common stock	—		—			—		(1,497		)	—			—				(1,497		)
Issuance of common stock and other, net	—		—			95		—			—			—				95
Purchases of treasury stock	—		(274		)	—		—			—			—				(274		)
Balance, December 31, 2011	$	177	$	(4,502	)	$	7,286	$	35,142		$	(483	)	$	—			$	37,620
Net income	—		—			—		4,598			—			—				4,598
Other comprehensive loss, net of tax	—		—			—		—			(19		)	—				(19		)
Dividends on common stock	—		—			—		(1,750		)	—			—				(1,750		)
Issuance of common stock and other, net	1		—			155		—			—			—				156
Noncontrolling interest contributions	—		—			—		—			—			32			(b)	32
Purchases of treasury stock	—		(589		)	—		—			—			—				(589		)
Balance, December 31, 2012	$	178	$	(5,091	)	$	7,441	$	37,990		$	(502	)	$	32			$	40,048

(a) On December 31, 2010, Occidental restructured its Colombian operations to take a direct working interest in the related assets.

(b) Reflects contributions from the noncontrolling interest in a pipeline company.

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

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Consolidated Statements of Cash Flows	Occidental Petroleum Corporation and Subsidiaries
In millions

For the years ended December 31,	2012			2011			2010
CASH FLOW FROM OPERATING ACTIVITIES
Net income	$	4,598		$	6,771		$	4,602
Adjustments to reconcile net income to net cash provided by operating activities:
Discontinued operations, net	37			(131		)	39
Depreciation, depletion and amortization of assets	4,511			3,591			3,153
Deferred income tax provision	1,128			1,436			406
Other noncash charges to income	195			190			231
Asset impairments and related items	1,751			—			275
Undistributed earnings from equity investments	(30		)	(33		)	(60		)
Dry hole expenses	279			160			139
Changes in operating assets and liabilities:
Decrease (increase) in receivables	472			(360		)	(929		)
(Increase) decrease in inventories	(265		)	(50		)	(42		)
Decrease in other current assets	127			95			210
(Decrease) increase in accounts payable and accrued liabilities	(1,086		)	657			1,146
Increase (decrease) in current domestic and foreign income taxes	1			(174		)	186
Other operating, net	(370		)	154			—
Operating cash flow from continuing operations	11,348			12,306			9,356
Operating cash flow from discontinued operations, net of taxes	(36		)	(25		)	210
Net cash provided by operating activities	11,312			12,281			9,566
CASH FLOW FROM INVESTING ACTIVITIES
Capital expenditures	(10,226		)	(7,518		)	(3,940		)
Payments for purchases of assets and businesses	(2,490		)	(4,909		)	(4,924		)
Sales of assets, net	4			50			20
Other, net	57			(96		)	(36		)
Investing cash flow from continuing operations	(12,655		)	(12,473		)	(8,880		)
Investing cash flow from discontinued operations	—			2,570			(415		)
Net cash used by investing activities	(12,655		)	(9,903		)	(9,295		)
CASH FLOW FROM FINANCING ACTIVITIES
Proceeds from long-term debt	1,736			2,111			2,584
Payments of long-term debt	—			(1,523		)	(311		)
Proceeds from issuance of common stock	85			50			10
Purchases of treasury stock	(583		)	(274		)	(67		)
Contributions from (distributions to) noncontrolling interest	32			(121		)	—
Cash dividends paid	(2,128		)	(1,436		)	(1,159		)
Other, net	12			18			26
Net cash (used) provided by financing activities	(846		)	(1,175		)	1,083
(Decrease) increase in cash and cash equivalents	(2,189		)	1,203			1,354
Cash and cash equivalents — beginning of year	3,781			2,578			1,224
Cash and cash equivalents — end of year	$	1,592		$	3,781		$	2,578

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

44

Notes to Consolidated Financial Statements Occidental Petroleum Corporation and Subsidiaries

NOTE 1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

NATURE OF OPERATIONS

In this report, "Occidental" means Occidental Petroleum Corporation, a Delaware corporation (OPC), or OPC and one or more entities in which it owns a controlling interest (subsidiaries). Occidental conducts its operations through various subsidiaries and affiliates. Occidental's principal businesses consist of the oil and gas, chemical and midstream, marketing and other (midstream and marketing) segments. The oil and gas segment explores for, develops and produces oil and condensate, natural gas liquids (NGLs) and natural gas. The chemical segment (OxyChem) mainly manufactures and markets basic chemicals and vinyls. The midstream and marketing segment gathers, processes, transports, stores, purchases and markets oil, condensate, NGLs, natural gas, carbon dioxide (CO₂) and power. It also trades around its assets, including transportation and storage capacity, and trades oil, NGLs, gas and other commodities. The segment also invests in entities that conduct similar activities.

PRINCIPLES OF CONSOLIDATION

The consolidated financial statements have been prepared in conformity with United States generally accepted accounting principles (GAAP) and include the accounts of OPC, its subsidiaries and its undivided interests in oil and gas exploration and production ventures. Occidental accounts for its share of oil and gas exploration and production ventures, in which it has a direct working interest, 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.

Certain financial statements, notes and supplementary data for prior years have been reclassified to conform to the 2012 presentation.

INVESTMENTS IN UNCONSOLIDATED ENTITIES

Occidental’s percentage interest in the underlying net assets of affiliates as to which it exercises significant influence without having a controlling interest (excluding oil and gas ventures in which Occidental holds an undivided interest) 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 may have occurred. The amount of impairment, if any, is based on quoted market prices, when available, or other valuation techniques, including discounted cash flows.

REVENUE RECOGNITION

Revenue is recognized from oil and gas production when title has passed to the customer, which occurs when the product is shipped. In international locations where oil is shipped by tanker, title passes when the tanker is loaded or product is received by the customer, depending on the shipping terms. This process occasionally causes a difference between actual production in a reporting period and sales volumes that have been recognized as revenue.

Revenue from chemical product sales is recognized when the product is shipped and title has passed to the customer. 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.

Revenue from marketing and trading activities is recognized on net settled transactions upon completion of contract terms and, for physical deliveries, upon title transfer. For unsettled transactions, contracts are recorded at fair value and changes in fair value are reflected in net sales. Revenue from all marketing and trading activities is reported on a net basis.

Occidental records revenue net of any taxes, such as sales taxes, that are assessed by governmental authorities on Occidental's customers.

RISKS AND UNCERTAINTIES

The process of preparing consolidated financial statements in conformity with GAAP requires Occidental's management to make informed estimates and judgments regarding certain types of financial statement balances and disclosures. Such estimates primarily relate to unsettled transactions and events as of the date of the consolidated financial statements and judgments on the materiality of transactions and balances. Changes in facts and circumstances or discovery of new information relating to such transactions and events may result in revised estimates and judgments and actual results may differ from estimates upon settlement but generally not by material amounts. Management believes that these estimates and judgments provide a reasonable basis for the fair presentation of Occidental’s financial statements.

Occidental establishes a valuation allowance against net operating losses and other deferred tax assets to the extent it believes the future benefit from these assets will not be realized in the statutory carryforward periods. Realization of deferred tax assets, including any net operating loss carryforwards, is dependent upon Occidental generating sufficient future taxable income and reversal of temporary differences in jurisdictions where such assets originate.

45

The accompanying consolidated financial statements include assets of approximately $12.3 billion as of December 31, 2012, and net sales of approximately $8.8 billion for the year ended December 31, 2012, 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, nationalizations, armed conflict, terrorism, insurgency, civil unrest, security problems, labor unrest, OPEC production restrictions, equipment import restrictions and sanctions, 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 affairs so as to mitigate its exposure to such risks and would seek compensation in the event of nationalization.

Because 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.

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 were approximately $1.0 billion and $3.5 billion at December 31, 2012 and 2011, respectively.

Investments

Available-for-sale securities are recorded at fair value with any unrealized gains or losses included in accumulated other comprehensive income/loss (AOCI). Trading securities are recorded at fair value with unrealized and realized gains or losses included in net sales.

Inventories

Materials and supplies are valued at weighted-average cost and are reviewed periodically for obsolescence. Oil, NGL and natural gas inventories are valued at the lower of cost or market.

For the chemical segment, Occidental's finished goods inventories are valued at the lower of cost or market. For most of its domestic inventories, other than materials and supplies, the chemical segment uses the last-in, first-out (LIFO) method as it better matches current costs and current revenue. For other countries, Occidental uses the first-in, first-out method (if the costs of goods are specifically identifiable) or the average-cost method (if the costs of goods are not specifically identifiable).

PROPERTY, PLANT AND EQUIPMENT

Oil and Gas

The carrying value of Occidental’s property, plant and equipment (PP&E) represents the cost incurred to acquire or develop the asset, including any asset retirement obligations and capitalized interest, net of accumulated depreciation, depletion and amortization (DD&A) and net of any impairment charges. For assets acquired, PP&E cost is based on fair values at the acquisition date. Asset retirement obligations and interest costs incurred in connection with qualifying capital expenditures are capitalized and amortized over the lives of the related assets.

Occidental uses the successful efforts method to account for its oil and gas properties. Under this method, Occidental capitalizes costs of acquiring properties, costs of drilling successful exploration wells and development costs. The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. If proved reserves have been found, the costs of exploratory wells remain capitalized. Otherwise, Occidental charges the costs of the related wells 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 generally expenses the costs of such exploratory wells if a determination of proved reserves has not been made within a 12-month period after drilling is complete.

The following table summarizes the activity of capitalized exploratory well costs for continuing operations for the years ended December 31:

In millions	2012			2011			2010
Balance — Beginning of Year	$	182		$	73		$	51
Additions to capitalized exploratory well costs pending the determination of proved reserves	400			334			112
Reclassifications to property, plant and equipment based on the determination of proved reserves	(407		)	(204		)	(73		)
Capitalized exploratory well costs charged to expense	(77		)	(21		)	(17		)
Balance — End of Year	$	98		$	182		$	73

Occidental expenses annual lease rentals and geological, geophysical and seismic costs as incurred.

Occidental expenses the costs of injectants used in production.

Occidental determines depreciation and depletion of oil and gas producing properties by the unit-of-production method.  It amortizes acquisition costs over total proved reserves, and capitalized development and successful exploration costs over proved developed reserves.

46

Proved oil and gas reserves (as defined in the Securities and Exchange Commission's Regulation S-X, Rule 4-10(a)) are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Occidental has no proved oil and gas reserves for which the determination of economic producibility is subject to the completion of major additional capital expenditures.

A portion of the carrying value of Occidental’s oil and gas properties is attributable to unproved properties. At December 31, 2012, the net capitalized costs attributable to unproved properties were $4.8 billion. The unproved amounts are not subject to DD&A until they are classified as proved properties. As exploration and development work progresses, if reserves on these properties are proved, capitalized costs attributable to the properties become subject to DD&A. If the exploration and development work were to be unsuccessful, or management's plans changed with respect to these properties, as a result of economic, operating or contractual conditions, the capitalized costs of the related properties would be expensed. The timing of any writedowns of these unproved properties, if warranted, depends upon management's plans, the nature, timing and extent of future exploration and development activities and their results. Occidental believes its current plans and exploration and development efforts will allow it to realize its unproved property balance.

Additionally, Occidental performs impairment tests with respect to its proved properties generally when prices decline other than temporarily, reserve estimates change significantly or other significant events occur that may impact its ability to realize the recorded asset amounts. Impairment tests incorporate a number of assumptions involving expectations of future cash flows, which can change significantly over time. These assumptions include estimates of future product prices, which Occidental bases on forward price curves and, when applicable, contractual prices, estimates of oil and gas reserves and estimates of future expected operating and development costs.

Fluctuations in commodity prices and production and development costs could cause management's plans to change with respect to unproved properties and could cause the carrying values of proved properties to be unrealizable. Such circumstances could result in impairments in the carrying values of proved or unproved properties or both.  Any impairment loss would be calculated as the excess of the asset’s net book value over its estimated fair value.

Chemical

Occidental’s chemical assets are depreciated using either the unit-of-production or the straight-line method, based upon the estimated useful lives of the facilities. The estimated useful lives of Occidental’s chemical assets, which range from three years to 50 years, are also used for impairment tests. The estimated useful lives 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. Such expenditures consist of ongoing routine repairs and maintenance, as well as planned major maintenance activities (PMMA). Ongoing routine repairs and maintenance expenditures are expensed as incurred. PMMA costs are capitalized and amortized over the period until the next planned overhaul. Additionally, Occidental incurs capital expenditures that extend the remaining useful lives of existing assets, increase their capacity or operating efficiency beyond the original specification or add value through modification for a different use. These capital expenditures are not considered in the initial determination of the useful lives of these assets at the time they are placed into service. The resulting revision, if any, of the asset’s estimated useful life is measured and accounted for prospectively.

Without these continued expenditures, the useful lives of these assets could decrease significantly. Other factors that could change the estimated useful lives of Occidental’s chemical assets include sustained higher or lower product prices, which are particularly affected by both domestic and foreign competition, demand, feedstock costs, energy prices, environmental regulations and technological changes.

Occidental performs impairment tests on its chemical assets whenever events or changes in circumstances lead to a reduction in the estimated useful lives or estimated future cash flows that would indicate that the carrying amount may not be recoverable, or when management’s plans change with respect to those assets. Any impairment loss would be calculated as the excess of the asset’s net book value over its estimated fair value.

Midstream and Marketing

Occidental’s midstream and marketing PP&E is depreciated over the estimated useful lives of the assets, using either the unit-of-production or straight-line method.

Occidental performs impairment tests on its midstream and marketing 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. Any impairment loss would be calculated as the excess of the asset’s net book value over its estimated fair value.

FAIR VALUE MEASUREMENTS

Occidental has categorized its assets and liabilities that are measured at fair value in a three-level fair value hierarchy, based on the inputs to the valuation techniques: Level 1 – using quoted prices in active markets for identical assets or liabilities; Level 2 – using observable inputs other than quoted prices for identical assets or liabilities; and Level 3 – using unobservable inputs. Transfers between levels, if any, are reported at the end of each reporting period.

47

Fair Values - Recurring

Occidental primarily applies the market approach for recurring fair value measurements, maximizes its use of observable inputs and minimizes its use of unobservable inputs. Occidental utilizes the mid-point price between bid and ask prices for valuing the majority of its assets and liabilities measured and reported at fair value. In addition to using market data, Occidental makes assumptions in valuing its assets and liabilities, including assumptions about the risks inherent in the inputs to the valuation technique. For assets and liabilities carried at fair value, Occidental measures fair value using the following methods:

Ø Commodity derivatives – Occidental values exchange-cleared commodity derivatives using closing prices provided by the exchange as of the balance sheet date. These derivatives are classified as Level 1. Over-the-Counter (OTC) bilateral financial commodity contracts, foreign exchange contracts, options and physical commodity forward purchase and sale contracts are generally valued using quotations provided by brokers or industry-standard models that consider various inputs, including quoted forward prices for commodities, time value, volatility factors, credit risk and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable prices at which transactions are executed in the marketplace. Occidental classifies these measurements as Level 2.

Ø Embedded commodity derivatives – Occidental values embedded commodity derivatives based on a market approach that considers various assumptions, including quoted forward commodity prices and market yield curves. The assumptions used include inputs that are observable and unobservable in the marketplace, and the fair value is designated as Level 3 within the valuation hierarchy.

Occidental generally uses an income approach to measure fair value when there is not a market-observable price for an identical or similar asset or liability. This approach utilizes management's judgments regarding expectations of projected cash flows, and discounts those cash flows using a risk-adjusted discount rate.

ACCRUED LIABILITIES—CURRENT

Accrued liabilities include accrued payroll, commissions and related expenses of $385 million and $462 million at December 31, 2012 and 2011, respectively.

ENVIRONMENTAL LIABILITIES AND EXPENDITURES

Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Occidental records environmental reserves for estimated remediation costs that relate to existing conditions from past operations when environmental remediation efforts are probable and the costs can be reasonably estimated. In determining the reserves and the range of reasonably possible additional losses, Occidental refers to currently available information, including relevant past experience, remedial objectives, available technologies, applicable laws and regulations and cost-sharing arrangements. Occidental bases environmental reserves on management’s estimate of the most likely cost to be incurred, using the most cost-effective technology reasonably expected to achieve the remedial objective. Occidental periodically reviews reserves and adjusts them as new information becomes available. Occidental records environmental reserves on a discounted basis when it deems the aggregate amount and timing of cash payments to be reliably determinable at the time the reserves are established. The reserve methodology with respect to discounting for a specific site is not modified once it is established. The amount of discounted environmental reserves is insignificant. Occidental generally records reimbursements or recoveries of environmental remediation costs in income when received, or when receipt of recovery is highly probable. As of December 31, 2012, 2011 and 2010, Occidental did not have any accruals for reimbursements or recoveries.

Many factors could affect Occidental’s future remediation costs and result in adjustments to its environmental reserves and range of reasonably possible additional losses. The most significant are: (1) cost estimates for remedial activities may be inaccurate; (2) the length of time, type or amount of remediation necessary to achieve the remedial objective may change due to factors such as site conditions, the ability to identify and control contaminant sources or the discovery of additional contamination; (3) a regulatory agency may ultimately reject or modify Occidental’s proposed remedial plan; (4) improved or alternative remediation technologies may change remediation costs; (5) laws and regulations may change remediation requirements or affect cost sharing or allocation of liability; and (6) changes in allocation or cost-sharing arrangements.

Certain sites involve multiple parties with various cost-sharing arrangements, which fall into the following three categories: (1) environmental proceedings that result in a negotiated or prescribed allocation of remediation costs among Occidental and other alleged potentially responsible parties; (2) oil and gas ventures in which each participant pays its proportionate share of remediation costs reflecting its working interest; or (3) contractual arrangements, typically relating to purchases and sales of properties, in which the parties to the transaction agree to methods of allocating remediation costs. In these circumstances, Occidental evaluates the financial viability of the other parties with whom it is alleged to be jointly liable, the degree of their commitment to participate and the consequences to Occidental of their failure to participate when estimating Occidental's ultimate share of liability. Occidental records reserves at its expected net cost of remedial activities and, based on these factors, believes that it will not be required to assume a share of liability of such other potentially responsible parties in an amount materially above amounts reserved.

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In addition to the costs of investigations and cleanup measures, which often take in excess of 10 years at Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA) National Priorities List (NPL) sites, Occidental’s reserves include management’s estimates of the costs to operate and maintain remedial systems. If remedial systems are modified over time in response to significant changes in site-specific data, laws, regulations, technologies or engineering estimates, Occidental reviews and adjusts its reserves accordingly.

ASSET RETIREMENT OBLIGATIONS

Occidental recognizes the fair value of asset retirement obligations in the period in which a determination is made that a legal obligation exists to dismantle an asset and reclaim or remediate the property at the end of its useful life and the cost of the obligation can be reasonably estimated. The liability amounts are based on future retirement cost estimates and incorporate many assumptions such as time to abandonment, technological changes, future inflation rates and the risk-adjusted discount rate. When the liability is initially recorded, Occidental capitalizes the cost by increasing the related PP&E balances. If the estimated future cost of the asset retirement obligation changes, Occidental records an adjustment to both the asset retirement obligation and PP&E. Over time, the liability is increased and expense is recognized for accretion, and the capitalized cost is depreciated over the useful life of the asset.

At a certain number of its facilities, Occidental has identified conditional asset retirement obligations that are related mainly to plant decommissioning. 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 $1,212 million and $1,030 million is included in deferred credits and other liabilities - other, with the remaining current portion in accrued liabilities at December 31, 2012 and 2011, respectively.

For the years ended December 31, (in millions)	2012			2011
Beginning balance	$	1,089		$	800
Liabilities incurred – capitalized to PP&E	86			74
Liabilities settled and paid	(58		)	(53		)
Accretion expense	61			48
Acquisitions and other – capitalized to PP&E	50			177
Revisions to estimated cash flows – capitalized to PP&E	38			43
Ending balance	$	1,266		$	1,089

DERIVATIVE INSTRUMENTS

Derivatives are carried at fair value and on a net basis when a legal right of offset exists with the same counterparty. Occidental applies hedge accounting when transactions meet specified criteria for cash-flow hedge treatment and management elects and documents such treatment. Otherwise, any fair value gains or losses are recognized in earnings in the current period. For cash-flow hedges, the gain or loss on the effective portion of the derivative is reported as a component of other comprehensive income (OCI) with an offsetting adjustment to the basis of the item being hedged. Realized gains or losses from cash-flow hedges, and any ineffective portion, are recorded as a component of net sales in the consolidated statements of income. Ineffectiveness is primarily created by a basis difference between the hedged item and the hedging instrument due to location, quality or grade of the physical commodity underlyingthe hedging instrument. Gains and losses from derivative instruments are reported net in the consolidated statements of income. There were no fair value hedges as of and during the years ended December 31, 2012, 2011 and 2010.

A hedge is regarded as highly effective such that it 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 will be offset by 80 to 125 percent of the changes in the fair value or cash flows, respectively, of the hedging instrument. In the case of hedging a forecast transaction, the transaction must be 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 hedged item matures or is sold or repaid; or when a forecast transaction is no longer deemed probable.

STOCK-BASED INCENTIVE PLANS

Occidental has established several stockholder-approved stock-based incentive plans for certain employees and directors (Plans) that are more fully described in Note 12. A summary of Occidental’s accounting policy for awards issued under the Plans follows.

For cash- and stock-settled restricted stock units or incentive award shares (RSUs), compensation value is initially measured on the grant date using the quoted market price of Occidental’s common stock. For total shareholder return incentives (TSRIs), compensation value is initially measured on the grant date using estimated payout levels derived from

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the Monte Carlo valuation model. Compensation expense for RSUs 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. Compensation expense for the cash-settled portion of TSRIs and related dividends is adjusted quarterly for any changes in the number of shares expected to be issued based on the performance criteria using the Monte Carlo valuation model. In addition, every quarter, compensation expense for the cash-settled portion of RSUs and TSRIs is adjusted for changes in the value of the underlying stock. All such performance or stock-price-related changes are recognized in periodic compensation expense. The stock-settled portion of all these awards is expensed using the initially measured compensation value.

EARNINGS PER SHARE

Occidental's instruments containing rights to nonforfeitable dividends granted in stock-based payment transactions are considered participating securities prior to vesting and, therefore, have been included in the earnings allocations in computing basic and diluted EPS under the two-class method.

Basic EPS was computed by dividing net income attributable to common stock, net of income allocated to participating securities, by the weighted-average number of common shares outstanding during each period, net of treasury shares and including vested but unissued shares and share units. The computation of diluted EPS reflects the additional dilutive effect of stock options and unvested stock awards.

RETIREMENT AND POSTRETIREMENT BENEFIT PLANS

Occidental recognizes the overfunded or underfunded amounts of its defined benefit pension and postretirement plans in its financial statements using a December 31 measurement date.

Occidental determines its defined benefit pension and postretirement benefit plan obligations based on various assumptions and discount rates. The discount rate assumptions used are meant to reflect the interest rate at which the obligations could effectively be settled on the measurement date. Occidental estimates the rate of return on assets with regard to current market factors but within the context of historical returns. Occidental funds and expenses negotiated pension increases for domestic union employees over the terms of the applicable collective bargaining agreements.

Pension and postretirement plan assets are measured at fair value. Common stock, preferred stock, publicly registered mutual funds, U.S. government securities and corporate bonds are valued using quoted market prices in active markets when available. When quoted market prices are not available, these investments are valued using pricing models with observable inputs from both active and non-active markets. Common and collective trusts are valued at the fund units' net asset value (NAV) provided by the issuer, which represents the quoted price in a non-active market. Short-term investment funds are valued at the fund units' NAV provided by the issuer.

SUPPLEMENTAL CASH FLOW INFORMATION

Occidental paid United States federal, state and foreign income taxes for continuing operations of approximately $2.4 billion, $2.9 billion and $2.4 billion during the years ended December 31, 2012, 2011 and 2010, respectively. Occidental also paid production, property and other taxes of approximately $694 million, $635 million and $510 million during the years ended December 31, 2012, 2011 and 2010, respectively, substantially all of which was in the United States. Interest paid totaled approximately $190 million, $315 million and $161 million for the years 2012, 2011 and 2010, respectively. The 2011 interest paid included $154 million of debt extinguishment premiums.

FOREIGN CURRENCY TRANSACTIONS

The functional currency applicable to all of Occidental’s foreign oil and gas operations is the United States dollar since cash flows are denominated principally in United States dollars. In Occidental's other operations, Occidental's use of non-United States dollar functional currencies was not material for all years presented. The effect of exchange rates on transactions in foreign currencies is included in periodic income. Occidental reports the exchange rate differences arising from translating foreign currency denominated balance sheet accounts to the United States dollar as of the reporting date in other comprehensive income. Exchange-rate gains and losses for continuing operations were not material for all years presented.

NOTE 2 ACQUISITIONS, DISPOSITIONS AND OTHER TRANSACTIONS

2012

During the year ended December 31, 2012, Occidental paid approximately $2.3 billion for domestic oil and gas properties in the Permian Basin, Williston Basin, South Texas and California.

In November 2012, Occidental and Magellan Midstream Partners, L.P. (Magellan) formed BridgeTex Pipeline Company, LLC (BridgeTex) and are proceeding with the construction of the BridgeTex Pipeline, which is expected to begin service in mid-2014. The approximately 450-mile-long pipeline will be capable of transporting approximately 300,000 barrels per day of crude oil between the Permian region (Colorado City, TX) and the Gulf Coast refinery markets. The BridgeTex Pipeline project also includes construction of approximately 2.6 million barrels of oil storage in aggregate.

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Occidental owns a 50% interest in BridgeTex and the remaining 50% interest is owned by Magellan, which also serves as the operator. BridgeTex was determined to be a variable interest entity because of the difference between Occidental's economic interests and its decision-making rights. Occidental is the primary beneficiary and consequently consolidates BridgeTex. At December 31, 2012, BridgeTex held approximately $50 million of money market mutual funds, classified as cash equivalents, which approximates fair value using Level 1 inputs. BridgeTex's assets cannot be used for the obligations of, nor do BridgeTex's creditors have recourse to, OPC or its other subsidiaries.

2011

During the year ended December 31, 2011, Occidental acquired producing properties in South Texas for approximately $1.8 billion.  Occidental also acquired approximately $2.6 billion of other domestic oil and gas assets, which included properties in California, as well as the Permian and Williston Basins.

In the first quarter of 2011, Occidental completed the sale of its Argentine oil and gas operations.

Internationally, in the first quarter of 2011, Occidental acquired a 40-percent participating interest in the Al Hosn gas project in Abu Dhabi, joining with the Abu Dhabi National Oil Company in a 30-year joint venture agreement. The project is operated by Abu Dhabi Gas Development Company Limited. In May 2011, Occidental paid approximately $500 million for its share of pre-acquisition development expenditures.

In early 2011, Occidental ceased exploration activity and its participation in production operations in Libya due to civil unrest in the country and United States sanctions. As a result, Occidental wrote off the entire amount of the capitalized and suspended exploration costs incurred to date, including lease acquisition costs, of approximately $35 million in the first quarter of 2011. The United States government lifted its sanctions in September 2011 and Occidental resumed its participation in the producing operations at that time.

2010

In December 2010, Occidental acquired oil producing and prospective properties in North Dakota for approximately $1.4 billion in cash. In 2010, Occidental also acquired various domestic oil and gas interests, in operated, producing and non-producing properties in the Permian Basin, Midcontinent region and California, for approximately $2.8 billion.

In December 2010, Occidental executed an agreement with a subsidiary of China Petrochemical Corporation (Sinopec) to sell its Argentine oil and gas operations for after-tax proceeds of approximately $2.6 billion.  Occidental recorded a pre-tax gain of $225 million when the sale closed in February 2011. Net revenues and pre-tax income for discontinued operations related to Argentina were $97 million and $2 million, respectively, for the year ended December 31, 2011.  Net revenues and pre-tax losses for such discontinued operations in 2010 were $700 million and $(39) million, respectively.

In December 2010, Occidental purchased additional noncontrolling interests in the general partner of Plains All-American Pipeline, L.P. (Plains Pipeline) for approximately $430 million, and now owns 35 percent of the general partner. In December 2010, Occidental also completed its acquisition of the remaining 50-percent joint venture interest in Elk Hills Power, LLC (EHP), a limited liability company that operates a gas-fired power-generation plant in California, for approximately $175 million, bringing Occidental’s total ownership to 100 percent. EHP is now consolidated in Occidental's balance sheet.

In January 2010, Occidental and other consortium members signed a 20-year contract with the South Oil Company of Iraq to develop the Zubair Field in Iraq.

NOTE 3 ACCOUNTING AND DISCLOSURE CHANGES

RECENTLY ADOPTED ACCOUNTING AND DISCLOSURE CHANGES

Fair Value Measurements

Beginning in the quarter ended March 31, 2012, Occidental enhanced its fair value measurement application and disclosures as a result of adopting new requirements issued by the Financial Accounting Standards Board in May 2011. The new rules include revisions to the standards for the use of fair value measurements and additional disclosures for: (i) all transfers between Level 1 and Level 2 of the fair value hierarchy; (ii) Level 3 measurements; and (iii) hierarchy classifications used for assets and liabilities whose fair value is disclosed only in the footnotes. The new rules did not have a material impact on Occidental.

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NOTE 4 INVENTORIES

Net carrying values of inventories valued under the LIFO method were approximately $185 million and $176 million at December 31, 2012 and 2011, respectively. Inventories consisted of the following:

Balance at December 31, (in millions)	2012			2011
Raw materials	$	70		$	69
Materials and supplies	612			443
Finished goods	763			655
	1,445			1,167
LIFO reserve	(101		)	(98		)
Total	$	1,344		$	1,069

NOTE 5 LONG-TERM DEBT

Long-term debt consisted of the following:

Balance at December 31, (in millions)	2012			2011
4.10% senior notes due 2021	$	1,300		$	1,300
1.75% senior notes due 2017	1,250			1,250
2.70% senior notes due 2023	1,250			—
3.125% senior notes due 2022	900			900
4.125% senior notes due 2016	750			750
2.5% senior notes due 2016	700			700
1.45% senior notes due 2013	600			600
1.50% senior notes due 2018	500			—
8.45% senior notes due 2029	116			116
9.25% senior debentures due 2019	116			116
7.2% senior debentures due 2028	82			82
Variable rate bonds due 2030 (0.13% and 0.11% as of December 31, 2012 and 2011, respectively)	68			68
8.75% medium-term notes due 2023	22			22
	7,654			5,904
Less:
Unamortized discount, net	(31		)	(33		)
Current maturities	(600		)	—
Total	$	7,023		$	5,871

Occidental has a bank credit facility (Credit Facility) with a $2.0 billion commitment expiring in 2016. No amounts have been drawn under this Credit Facility. Up to $1.0 billion 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 average annual facility fees of 0.08 percent in 2012 on the total commitment amounts of the Credit Facility.

The Credit Facility provides for the termination of loan commitments and requires immediate repayment of any outstanding amounts if certain events of default occur. The Credit Facility and other debt agreements do not contain material adverse change clauses or debt ratings triggers that could restrict Occidental's ability to borrow or that would permit lenders to terminate their commitments or accelerate debt.

As of December 31, 2012, under the most restrictive covenants of its financing agreements, Occidental had substantial capacity for additional unsecured borrowings, the payment of cash dividends and other distributions on, or acquisitions of, Occidental stock.

In June 2012, Occidental issued $1.75 billion of debt which comprised $1.25 billion of 2.70-percent senior unsecured notes due 2023 and $500 million of 1.50-percent senior unsecured notes due 2018. Occidental received net proceeds of approximately $1.74 billion. Interest on the notes will be payable semi-annually in arrears in February and August for each series of notes.

In August 2011, Occidental issued $2.15 billion of debt, which comprised $1.25 billion of 1.75-percent senior unsecured notes due 2017 and $900 million of 3.125-percent senior unsecured notes due 2022. Occidental received net proceeds of approximately $2.1 billion. Interest on the notes is payable semi-annually in arrears in February and August for each series of notes.

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In March 2011, Occidental redeemed all $1.0 billion of its outstanding 7-percent senior notes due 2013 and all $368 million of its outstanding 6.75-percent senior notes due 2012.  Occidental recorded a $163 million pre-tax charge related to this redemption in the first quarter of 2011.

In December 2010, Occidental issued $2.6 billion of debt, which comprised $600 million of 1.45-percent senior unsecured notes due 2013, $700 million of 2.50-percent senior unsecured notes due 2016 and $1.3 billion of 4.10-percent senior unsecured notes due 2021.  Occidental received net proceeds of approximately $2.6 billion.  Interest on the notes is payable semi-annually in arrears in June and December of each year for the 1.45-percent notes and February and August of each year for the other notes.

Occidental has provided guarantees on Dolphin Energy's debt, which are limited to certain political and other events. At December 31, 2012 and 2011, Occidental’s total guarantees were not material and a substantial majority of the amounts consisted of limited recourse guarantees on approximately $370 million and $300 million, respectively, of Dolphin’s debt, of which the fair value was immaterial.

At December 31, 2012, principal payments on long-term debt aggregated $7.6 billion, of which $0.6 billion is due in 2013, $0.0 billion in 2014, $0.0 billion in 2015, $1.4 billion in 2016, $1.2 billion in 2017 and $4.4 billion in 2018 and thereafter.

Occidental estimates the fair value of fixed-rate debt based on the quoted market prices for those instruments or on quoted market yields for similarly rated debt instruments, taking into account such instruments' maturities. The estimated fair values of Occidental’s debt at December 31, 2012 and 2011, which were classified as Level 1, were approximately $8.2 billion and $6.4 billion, respectively, compared to carrying values of approximately $7.6 billion and $5.9 billion, respectively. Occidental's exposure to changes in interest rates relates primarily to its variable-rate, long-term debt obligations, and is not material. As of December 31, 2012 and 2011, variable-rate debt constituted approximately 1 percent of Occidental's total debt.

NOTE 6 LEASE COMMITMENTS

Operating lease agreements include leases for transportation equipment, power plants, machinery, terminals, storage facilities, land and office space. Occidental’s operating lease agreements frequently include renewal or purchase options and require it to pay for utilities, taxes, insurance and maintenance expense. At December 31, 2012, future net minimum lease payments for noncancelable operating leases (excluding oil and gas and other mineral leases, utilities, taxes, insurance and maintenance expense) were the following:

In millions	Amount (a)
2013	$	158
2014	105
2015	106
2016	88
2017	59
Thereafter	460
Total minimum lease payments	$	976

(a) These amounts are net of sublease rentals of $3 million, which are to be received as follows (in millions):  2013—$2 and 2014—$1.

Rental expense for operating leases, net of sublease rental income for continuing operations, was $176 million in 2012, $179 million in 2011 and $170 million in 2010. Rental expense was net of sublease income of $4 million each in 2012, 2011 and 2010.

NOTE 7 DERIVATIVES

Objective & Strategy

Occidental uses a variety of derivative instruments, including cash-flow hedges and derivative instruments not designated as hedging instruments, to establish, as of the date of production, the price it receives and to improve realized prices for oil and gas. Occidental only occasionally hedges its oil and gas production and, when it does, the volumes are usually insignificant. Additionally, Occidental’s Phibro trading unit engages in trading activities using derivatives for the purpose of generating profits mainly from market price changes of commodities.

Refer to Note 1 for Occidental’s accounting policy on derivatives.

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Cash-Flow Hedges

Occidental entered into financial swap agreements in November 2012 for the sale of a portion of its natural gas production in California. These swap agreements hedge 50 million cubic feet of natural gas per day beginning in January 2013 through March 2014 and qualify as cash-flow hedges. The weighted-average strike price of these swaps was $4.30.

Through March 31, 2012, Occidental held financial swap agreements related to the sale of 50 million cubic feet per day of its existing natural gas production from the Rocky Mountain region of the United States that qualified as cash-flow hedges at a weighted-average strike price of $6.07.

Through December 31, 2011, Occidental held a series of collar agreements for 12,000 barrels of oil per day of its domestic production that qualified as cash-flow hedges at a weighted-average strike price that ranged from $32.92 to $46.35.

Occidental’s marketing and trading operations store natural gas purchased from third parties at Occidental’s North American leased storage facilities. Derivative instruments are used to fix margins on the future sales of the stored volumes through March 31, 2013. As of December 31, 2012 and 2011, Occidental had approximately 20 billion cubic feet and 25 billion cubic feet of natural gas held in storage, respectively. As of December 31, 2012 and 2011, Occidental had cash-flow hedges for the forecast sale, to be settled by physical delivery, of approximately 20 billion cubic feet and 35 billion cubic feet of this stored natural gas, respectively.

The following table presents the pre-tax and after-tax gains and losses recognized in, and reclassified to income from, AOCI, for derivative instruments classified as cash-flow hedges for the years ended December 31, 2012 and 2011 (in millions):

	After-tax						Pre-Tax
	2012			2011			2012			2011
Beginning Balance — AOCI	$	1		$	(111	)
Unrealized gains recognized in AOCI	16			14			$	25		$	20
(Gains) losses reclassified to income	(24		)	98			$	(38	)	$	154
Ending Balance — AOCI	$	(7	)	$	1

Occidental expects that during the next twelve months an insignificant amount of net after-tax derivative losses included in AOCI based on their valuation as of December 31, 2012, will be reclassified into income. The gains and losses reclassified to income were recognized in net sales, and the amount of the ineffective portion of cash-flow hedges was immaterial for the years ended December 31, 2012 and 2011.

Derivatives Not Designated as Hedging Instruments

The following table summarizes Occidental's net volumes resulting from outstanding commodity derivatives contracts not designated as hedging instruments, including both financial and physical derivative contracts as of December 31, 2012 and 2011:

	Net Outstanding Position Long / (Short)
Commodity	2012		2011
Oil (million barrels)	(17	)	(9	)
Natural gas (billion cubic feet)	(217	)	(242	)
Precious metals (million troy ounces)	1		3

In addition, Occidental typically has certain other commodity trading contracts, such as agricultural products, power and other metals, as well as foreign exchange contracts. These contracts were not material to Occidental as of December 31, 2012 and 2011.

Occidental fulfills its short positions through its own production or by third-party purchase contracts. Subsequent to December 31, 2012, Occidental entered into purchase contracts for a substantial portion of the outstanding positions at year-end and has sufficient production capacity and the ability to enter into additional purchase contracts to satisfy the remaining positions.

Approximately $49 million and $94 million of net gains from derivatives not designated as hedging instruments were recognized in net sales for the years ended December 31, 2012 and 2011, respectively.

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Fair Value of Derivatives

The following table presents the gross fair value of Occidental’s outstanding derivatives as of December 31, 2012 and 2011 (in millions):

December 31, 2012	Asset Derivatives Balance Sheet Location	Fair Value			Liability Derivatives Balance Sheet Location	Fair Value
Cash-flow hedges (a)
Commodity contracts	Other current assets	$	11		Accrued liabilities	$	1
	Long-term receivables and other assets, net	—			Deferred credits and other liabilities	1
		$	11			$	2
Derivatives not designated as hedging instruments (a)
Commodity contracts	Other current assets	$	386		Accrued liabilities	$	479
	Long-term receivables and other assets, net	22			Deferred credits and other liabilities	16
		408				495
Total gross fair value		419				497
Less: counterparty netting and cash collateral (b)		(301		)		(371		)
Total net fair value of derivatives		$	118			$	126

December 31, 2011	Asset Derivatives Balance Sheet Location	Fair Value			Liability Derivatives Balance Sheet Location	Fair Value
Cash-flow hedges (a)
Commodity contracts	Other current assets	$	41		Accrued liabilities	$	5
	Long-term receivables and other assets, net	3			Deferred credits and other liabilities	—
		$	44			$	5
Derivatives not designated as hedging instruments (a)
Commodity contracts	Other current assets	$	835		Accrued liabilities	$	887
	Long-term receivables and other assets, net	71			Deferred credits and other liabilities	71
		906				958
Total gross fair value		950				963
Less: counterparty netting and cash collateral (c)		(758		)		(782		)
Total net fair value of derivatives		$	192			$	181

(a) Fair values are presented at gross amounts, including when the derivatives are subject to master netting arrangements and qualify for net presentation in the consolidated balance sheet.

(b) As of December 31, 2012, collateral received of $25 million has been netted against derivative assets and collateral paid of $95 million has been netted against derivative liabilities.

(c) As of December 31, 2011, collateral received of $42 million has been netted against derivative assets and collateral paid of $66 million has been netted against derivative liabilities.

See Note 15 for fair value measurement disclosures on derivatives.

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Credit Risk

A substantial portion of Occidental’s derivative transaction volume is executed through exchange-traded contracts, which are subject to nominal credit risk as a significant portion of these transactions is settled on a daily margin basis with select clearinghouses and brokers. Collateral of $116 million and $173 million deposited by Occidental for such contracts, which has not been reflected in the derivative fair value tables, is included in the other current assets balance as of December 31, 2012 and 2011, respectively.

Occidental executes the rest of its derivative transactions in the OTC market. Occidental is subject to counterparty credit risk to the extent the counterparty to the derivatives is unable to meet its settlement commitments. Occidental manages this credit risk by selecting counterparties that it believes to be financially strong, by spreading the credit risk among many such counterparties, by entering into master netting arrangements with the counterparties and by requiring collateral, as appropriate. Occidental actively monitors the creditworthiness of each counterparty and records valuation adjustments to reflect counterparty risk, if necessary.

Certain of Occidental's OTC derivative instruments contain credit-risk-contingent features, primarily tied to credit ratings for Occidental or its counterparties, which may affect the amount of collateral that each would need to post. As of December 31, 2012 and 2011, Occidental had a net liability of $34 million and $58 million, respectively, which are net of collateral posted of $64 million and $27 million, respectively. Occidental believes that if it had received a one-notch reduction in its credit ratings, it would not have resulted in a material change in its collateral-posting requirements as of December 31, 2012 and 2011.

Foreign Currency Risk

Occidental’s foreign operations have limited currency risk. Occidental manages its exposure primarily by balancing monetary assets and liabilities and limiting cash positions in foreign currencies to levels necessary for operating purposes.  A vast majority of international oil sales are denominated in United States dollars. Additionally, all of Occidental’s consolidated foreign oil and gas subsidiaries have the United States dollar as the functional currency.

NOTE 8 ENVIRONMENTAL LIABILITIES AND EXPENDITURES

Occidental’s operations are subject to stringent federal, state, local and foreign laws and regulations related to improving or maintaining environmental quality. 

ENVIRONMENTAL REMEDIATION

The laws that require or address environmental remediation, including CERCLA and similar federal, state, local and foreign laws, may apply retroactively and regardless of fault, the legality of the original activities or the current ownership or control of sites. OPC or certain of its subsidiaries participate in or actively monitor a range of remedial activities and government or private proceedings under these laws with respect to alleged past practices at operating, closed and third-party sites. Remedial activities may include one or more of the following: investigation involving sampling, modeling, risk assessment or monitoring; cleanup measures including removal, treatment or disposal; or operation and maintenance of remedial systems. The environmental proceedings seek funding or performance of remediation and, in some cases, compensation for alleged property damage, punitive damages, civil penalties, injunctive relief and government oversight costs.

As of December 31, 2012, Occidental participated in or monitored remedial activities or proceedings at 161 sites. The following table presents Occidental’s environmental remediation reserves as of December 31, 2012, 2011 and 2010, the current portion of which is included in accrued liabilities ($80 million in 2012, $79 million in 2011 and $79 million in 2010) and the remainder in deferred credits and other liabilities — other ($264 million in 2012, $281 million in 2011 and $287 million in 2010). The reserves are grouped as environmental remediation sites listed or proposed for listing by the U.S. Environmental Protection Agency on the CERCLA National Priorities List (NPL sites) and three categories of non-NPL sites — third-party sites, Occidental-operated sites and closed or non-operated Occidental sites.

$ amounts in millions	2012			2011			2010
	Number of Sites	Reserve Balance		Number of Sites	Reserve Balance		Number of Sites	Reserve Balance
NPL sites	35	$	54	36	$	63	38	$	56
Third-party sites	75	84		73	88		83	91
Occidental-operated sites	22	123		22	120		20	122
Closed or non-operated Occidental sites	29	83		29	89		29	97
Total	161	$	344	160	$	360	170	$	366

As of December 31, 2012, Occidental’s environmental reserves exceeded $10 million each at 12 of the 161 sites described above, and 112 of the sites had reserves from $0 to $1 million each.

As of December 31, 2012, two landfills in western New York owned by Occidental accounted for 73 percent of its reserves associated with NPL sites. In connection with a 1986 acquisition, Maxus Energy Corporation has retained the liability and indemnified Occidental for 14 of the remaining NPL sites.

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As of December 31, 2012, Maxus has also retained the liability and indemnified Occidental for 8 of the 75 third-party sites. Two of the remaining 67 third-party sites — a former copper mining and smelting operation in Tennessee and a containment and removal project in Tennessee — accounted for 43 percent of Occidental’s reserves associated with these sites.

Five sites — chemical plants in Kansas, Louisiana, Texas and New York and a group of oil and gas properties in the southwestern United States — accounted for 70 percent of the reserves associated with the Occidental-operated sites.

Three other sites — former chemical plants in Tennessee and Delaware and a closed coal mine in Pennsylvania — accounted for 55 percent of the reserves associated with closed or non-operated Occidental sites.

Environmental reserves vary over time depending on factors such as acquisitions or dispositions, identification of additional sites and remedy selection and implementation. The following table presents environmental reserve activity for the past three years:

In millions	2012			2011			2010
Balance — Beginning of Year	$	360		$	366		$	403
Remediation expenses and interest accretion	56			53			26
Changes from acquisitions/dispositions	—			14			3
Payments	(72		)	(73		)	(66		)
Balance — End of Year	$	344		$	360		$	366

Based on current estimates, Occidental expects to expend funds corresponding to approximately half of the current environmental reserves at the sites described above over the next four years and the balance at these sites over the subsequent 10 or more years. Occidental believes its range of reasonably possible additional losses beyond those liabilities recorded for environmental remediation at these sites could be up to $375 million.

ENVIRONMENTAL COSTS

Occidental’s environmental costs, some of which include estimates, are presented below for each segment for each of the years ended December 31:

In millions	2012		2011		2010
Operating Expenses
Oil and Gas	$	160	$	158	$	108
Chemical	70		68		72
Midstream and Marketing	20		21		13
	$	250	$	247	$	193
Capital Expenditures
Oil and Gas	$	122	$	110	$	72
Chemical	18		15		19
Midstream and Marketing	12		15		13
	$	152	$	140	$	104
Remediation Expenses
Corporate	$	56	$	52	$	25

Operating expenses are incurred on a continual basis. Capital expenditures relate to longer-lived improvements in currently operating properties. Remediation expenses relate to existing conditions from past operations.

NOTE 9 LAWSUITS, CLAIMS, COMMITMENTS AND CONTINGENCIES

OPC or certain of its subsidiaries are involved, in the normal course of business, in lawsuits, claims and other legal proceedings that seek, among other things, compensation for alleged personal injury, breach of contract, property damage or other losses, punitive damages, civil penalties, or injunctive or declaratory relief. OPC or certain of its subsidiaries also are involved 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, civil penalties and injunctive relief. Usually OPC or such subsidiaries are among many companies in these environmental proceedings and have to date been successful in sharing response costs with other financially sound companies. Further, some lawsuits, claims and legal proceedings involve acquired assets with respect to which third-parties retain liability or indemnify Occidental for conditions that existed prior to purchase.

Occidental accrues reserves for currently outstanding lawsuits, claims and proceedings when it is probable that a liability has been incurred and the liability can be reasonably estimated. Occidental has disclosed its reserve balances for environmental matters. Reserve balances for other matters as of December 31, 2012 and 2011, were not material to

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Occidental's consolidated balance sheets. Occidental also evaluates the amount of reasonably possible losses that it could incur as a result of the matters mentioned above. Occidental has disclosed its range of reasonably possible additional losses for sites where it is a participant in environmental remediation. Occidental believes that other reasonably possible losses that it could incur in excess of reserves accrued on the balance sheet would not be material to its consolidated financial position or results of operations.

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. Although taxable years through 2009 for United States federal income tax purposes have been audited by the United States Internal Revenue Service (IRS) pursuant to its Compliance Assurance Program, subsequent taxable years are currently under review. Additionally, in December 2012, Occidental filed United States federal refund claims for tax years 2008 and 2009 which are subject to IRS review. Taxable years from 2000 through the current year remain subject to examination by foreign and state government tax authorities in certain jurisdictions. In certain of these jurisdictions, tax authorities are in various stages of auditing Occidental’s income taxes. During the course of tax audits, disputes have arisen and other disputes may arise as to facts and matters of law. Occidental believes that the resolution of outstanding tax matters would not have a material adverse effect on its consolidated financial position or results of operations.

OPC, its subsidiaries or both have entered into agreements providing for future payments to secure terminal and pipeline capacity, drilling rigs and services, electrical power, steam and certain chemical raw materials. 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. At December 31, 2012, total purchase obligations were $8.7 billion, which included approximately $2.7 billion, $1.4 billion, $700 million, $500 million and $400 million that will be paid in 2013, 2014, 2015, 2016 and 2017, respectively. Included in the purchase obligations are commitments for major fixed and determinable capital expenditures during 2013 and thereafter, which were approximately $2.2 billion.

OPC, its subsidiaries or both have indemnified various parties against specified liabilities 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, 2012, Occidental is not aware of circumstances that it believes would reasonably be expected to lead to indemnity claims that would result in payments materially in excess of reserves.

NOTE 10 DOMESTIC AND FOREIGN INCOME TAXES

The domestic and foreign components of income from continuing operations before domestic and foreign income taxes and net of noncontrolling interest amounts were as follows:

For the years ended December 31, (in millions)	Domestic			Foreign		Total
2012	$	2,117	(a)	$	5,636	$	7,753
2011	$	4,806		$	6,035	$	10,841
2010	$	3,295		$	4,269	$	7,564

(a) Includes pre-tax charges of $1.8 billion for the impairment of domestic gas assets and related items.

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

For the years ended December 31, (in millions)	United States Federal			State and Local		Foreign		Total
2012
Current	$	(401	)	$	8	$	2,383	$	1,990
Deferred	1,046			41		41		1,128
	$	645		$	49	$	2,424	$	3,118
2011
Current	$	320		$	88	$	2,357	$	2,765
Deferred	1,340			47		49		1,436
	$	1,660		$	135	$	2,406	$	4,201
2010
Current	$	614		$	79	$	1,896	$	2,589
Deferred	390			4		12		406
	$	1,004		$	83	$	1,908	$	2,995

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

For the years ended December 31,	2012		2011		2010
United States federal statutory tax rate	35	%	35	%	35	%
Operations outside the United States	5		4		5
State income taxes, net of federal benefit	1		1		1
Other	(1	)	(1	)	(1	)
Worldwide effective tax rate	40	%	39	%	40	%

The tax effects of temporary differences resulting in deferred income taxes at December 31, 2012 and 2011 were as follows:

	2012					2011
Tax effects of temporary differences (in millions)	Deferred Tax Assets			Deferred Tax Liabilities		Deferred Tax Assets			Deferred Tax Liabilities
Property, plant and equipment differences	$	—		$	7,316	$	—		$	6,039
Equity investments, partnerships and foreign subsidiaries	—			351		—			351
Environmental reserves	126			—		131			—
Postretirement benefit accruals	413			—		410			—
Deferred compensation and benefits	278			—		286			—
Asset retirement obligations	367			—		318			—
Foreign tax credit carryforwards	1,277			—		1,240			—
Other tax credit carryforwards	195			—		—			—
Federal benefit of state income taxes	89			—		104			—
All other	334			161		374			116
Subtotal	3,079			7,828		2,863			6,506
Valuation allowance	(1,040		)	—		(1,003		)	—
Total deferred taxes	$	2,039		$	7,828	$	1,860		$	6,506

Included in total deferred tax assets was a current portion aggregating $250 million and $200 million as of December 31, 2012 and 2011, respectively, that was reported in other current assets. Total deferred tax assets were $2.0 billion and $1.9 billion as of December 31, 2012 and 2011, respectively, the noncurrent portion of which is netted against deferred tax liabilities. Occidental expects to realize the recorded deferred tax assets, net of any allowances, through future operating income and reversal of temporary differences.

Occidental had, as of December 31, 2012, foreign tax credit carryforwards of $1.3 billion, which expire in varying amounts through 2022, and various state operating loss carryforwards, which have varying carryforward periods through 2025. Substantially all of Occidental's valuation allowance is provided for foreign tax credit and state operating loss carryforwards.

A deferred tax liability has not been recognized for temporary differences related to unremitted earnings of certain consolidated foreign subsidiaries aggregating approximately $8.1 billion at December 31, 2012, 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 $116 million would be required, assuming utilization of available foreign tax credits.

Discontinued operations include income tax charges of $7 million and $86 million in 2012 and 2011, respectively, and income tax benefits of $26 million in 2010.

Additional paid-in capital was credited $8 million in 2012, $14 million in 2011 and $22 million in 2010 for an excess tax benefit from the exercise of certain stock-based compensation awards.

As of December 31, 2012, Occidental had liabilities for unrecognized tax benefits of approximately $76 million included in deferred credits and other liabilities – other, all of which, if subsequently recognized, would favorably affect Occidental’s effective tax rate.

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

For the years ended December 31, (in millions)	2012			2011
Balance at January 1,	$	67		$	38
Additions based on tax positions related to the current year	16			44
Reductions based on tax positions related to prior years and settlements	(7		)	(15		)
Balance at December 31,	$	76		$	67

Occidental records estimated potential interest and penalties related to liabilities for unrecognized tax benefits in the provisions for domestic and foreign income taxes and these amounts were not material for the years ended December 31, 2012, 2011 and 2010.

Occidental is subject to audit by various tax authorities in varying periods. See Note 9 for a discussion of these matters.

Management believes it is unlikely that Occidental’s liabilities for unrecognized tax benefits related to existing matters would increase or decrease within the next twelve months by a material amount. 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 a summary of common stock issuances:

Shares in thousands	Common Stock
Balance, December 31, 2009	883,643
Issued	967
Options exercised and other, net	665
Balance, December 31, 2010	885,275
Issued	1,302
Options exercised and other, net	232
Balance, December 31, 2011	886,809
Issued	1,746
Options exercised and other, net	246
Balance, December 31, 2012	888,801

TREASURY STOCK

Occidental has had a 95 million share repurchase program authorized since 2008; however, the program does not obligate Occidental to acquire any specific number of shares and may be discontinued at any time. In 2012 and 2011, respectively, Occidental purchased 7.2 million and 2.7 million shares under the program at an average cost of $77.98 and $77.12 per share.

Additionally, Occidental purchased shares from the trustee of its defined contribution savings plan during the years ended December 31, 2012, 2011 and 2010.

As of December 31, 2012, 2011 and 2010, treasury stock shares numbered 83.3 million, 75.8 million and 72.5 million, respectively.

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, 2012, 2011 and 2010, Occidental had no outstanding shares of preferred stock.

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EARNINGS PER SHARE

The following table presents the calculation of basic and diluted EPS for the years ended December 31:

In millions, except per-share amounts	2012				2011			2010
Basic EPS
Income from continuing operations	$	4,635		(a)	$	6,640		$	4,641
Less: Income from continuing operations attributable to noncontrolling interest	—				—			(72		)
Income from continuing operations attributable to common stock	4,635				6,640			4,569
Discontinued operations, net	(37		)		131			(39		)
Net income attributable to common stock	4,598				6,771			4,530
Less: Net income allocated to participating securities	(8		)		(11		)	(6		)
Net income attributable to common stock, net of participating securities	$	4,590			$	6,760		$	4,524
Weighted average number of basic shares	809.3				812.1			812.5
Basic EPS	$	5.67			$	8.32		$	5.57
Diluted EPS
Net income attributable to common stock, net of participating securities	$	4,590			$	6,760		$	4,524
Weighted average number of basic shares	809.3				812.1			812.5
Dilutive effect of potentially dilutive securities	0.7				0.8			1.3
Total diluted weighted average common shares	810.0				812.9			813.8
Diluted EPS	$	5.67			$	8.32		$	5.56

(a) Includes after-tax charges of $1.1 billion for the impairment of domestic gas assets and related items.

ACCUMULATED OTHER COMPREHENSIVE LOSS

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

Balance at December 31, (in millions)	2012			2011
Foreign currency translation adjustments	$	(34	)	$	(9	)
Unrealized gains (losses) on derivatives	(7		)	1
Pension and post-retirement adjustments (a)	(461		)	(475		)
Total	$	(502	)	$	(483	)

(a) See Note 13 for further information.

NOTE 12 STOCK-BASED INCENTIVE PLANS

Occidental has established several Plans that allow it to issue stock-based awards in the form of RSUs, stock options (Options), stock appreciation rights (SARs) and TSRIs. An aggregate of 66 million shares of Occidental common stock were authorized for issuance and approximately 15 million shares had been issued through December 31, 2012. Of the remaining shares, approximately 19 million shares are available for grants of future awards because a plan provision requires each share covered by an award (other than Options and SARs) to be counted as if three shares were issued in determining the number of shares that otherwise would have been available for future awards. Further, the number of shares available for future awards may be less than 19 million depending on the type of award granted. Additionally, under the plan, the shares available for future awards may increase by the number of shares currently unvested or forfeitable, or three times that number as applicable, that (i) fail to vest, (ii) are forfeited or cancelled, or (iii) correspond to the portion of any stock-based awards settled in cash.

During 2012, non-employee directors were granted awards for 53,800 shares of restricted stock that fully vested on the grant date. Compensation expense for these awards was measured using the quoted market price of Occidental's common stock on the grant date and was fully recognized at that time.

The following table summarizes certain stock-based incentive amounts for the past three years:

For the years ended December 31, (in millions)	2012		2011		2010
Compensation expense	$	78	$	110	$	136
Income tax benefit recognized in the income statement	$	29	$	40	$	50
Intrinsic value of options and stock-settled SARs exercised	$	18	$	21	$	74
Cash paid (a)	$	83	$	124	$	97
Fair value of RSUs and TSRIs vested during the year (b)	$	28	$	53	$	19

(a) Includes cash paid under the cash-settled portion of the SARs, RSUs and TSRIs.

(b) As measured on the vesting date for the stock-settled portion of the RSUs and TSRIs.

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As of December 31, 2012, unrecognized compensation expense for all unvested stock-based incentive awards, based on year-end valuation, was $196 million. This expense is expected to be recognized over a weighted-average period of 2.1 years.

RSUs

Certain employees are awarded the right to receive RSUs, some of which have performance criteria, and are, or are equivalent in value to, actual shares of Occidental common stock and are settled in cash or stock at the time of vesting. These awards vest at the end of, or ratably over, two or three years from the grant date, however, certain of the RSUs are forfeitable if performance objectives are not satisfied between the third and seventh anniversaries after the grant date. For those awards that cliff vest in two years, dividend equivalents are accumulated during the vesting period and are paid when they vest. For the remaining RSUs, dividend equivalents are paid during the vesting period. The weighted-average, grant-date fair values of cash-settled RSUs granted in 2012, 2011 and 2010 were $84.38, $104.74 and $77.14 per share, respectively. The weighted-average, grant-date fair values of the stock-settled RSUs granted in 2012, 2011, and 2010 were $84.81, $102.97 and $84.29 respectively.

A summary of changes in Occidental’s unvested cash- and stock-settled RSUs during the year ended December 31, 2012 is presented below:

	Cash-Settled				Stock-Settled
	RSUs (000's)		Weighted-Average Grant-Date Fair Value		RSUs (000's)		Weighted-Average Grant-Date Fair Value
Unvested at January 1	1,272		$	90.50	568		$	93.14
Granted	729		$	84.38	824		$	84.81
Vested	(621	)	$	83.61	(9	)	$	88.21
Forfeitures	(48	)	$	92.90	(8	)	$	84.57
Unvested at December 31	1,332		$	90.27	1,375		$	88.23

STOCK OPTIONS AND SARs

Certain employees have been granted Options that are settled in stock and SARs that are settled either only in stock or only in cash. No Options or SARs have been granted since 2006 and all outstanding awards are vested. Exercise prices of the Options and SARs were equal to the quoted market value of Occidental’s stock on the grant date. Generally, the Options and SARs vest ratably over three years from the grant date 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, stock-settled SAR or cash-settled SAR is initially measured on the grant date using the Black Scholes option valuation model. 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 T-notes (US Treasury Strip) at the grant date with a remaining term equal to the expected life of the measured instrument. 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 may not accurately predict the value ultimately realized by employees who receive stock-based incentive awards, and the ultimate value may not be indicative of the reasonableness of the original estimates of fair value made by Occidental.

The following is a summary of Option and SAR transactions during the year ended December 31, 2012:

	Cash-Settled							Stock-Settled
	SARs (000's)		Weighted- Average Exercise Price		Weighted- Average Remaining Contractual Term (yrs)	Aggregate Intrinsic Value (000’s)		SARs & Options (000's)		Weighted- Average Exercise Price		Weighted- Average Remaining Contractual Term (yrs)	Aggregate Intrinsic Value (000’s)
Beginning balance, January 1	564		$	24.66				782		$	26.34
Exercised	(70	)	$	24.66				(245	)	$	14.22
Ending balance, December 31	494		$	24.66	1.5	$	25,639	537		$	31.88	2.0	$	24,008
Exercisable at December 31	494		$	24.66	1.5	$	25,639	537		$	31.88	2.0	$	24,008

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TSRIs

Certain executives are awarded TSRIs that vest at the end of the three- or four-year period following the grant date if performance targets are certified as being met. TSRIs granted in July 2012 have payouts that range from 0 to 100 percent of the maximum award that would settle, once certified, fully in stock. TSRIs granted in July 2011 and October 2010 have payouts that range from 0 to 100 percent of the maximum award that would settle, once certified, 50 percent in stock and 50 percent in cash. TSRIs granted in July 2009 have payouts that ranged from 0 to 200 percent of the target award that would settle, once certified, 60 percent in stock and 40 percent in cash. TSRIs granted in July 2008 had payouts of 150 percent of the target award and were certified and settled equally in stock and cash in 2012. Dividend equivalents for TSRI target shares are paid during the performance period regardless of the payout range or settlement provision, except for the TSRIs issued in 2010, 2011 and 2012, for which cumulative dividends will be paid upon vesting for the number of vested shares.

The fair values of TSRIs are initially determined on the grant date using a Monte Carlo simulation model based on Occidental's assumptions, noted in the following table, and the volatility from corresponding peer group companies. The expected life is based on the vesting period (Term). The risk-free interest rate is the implied yield available on zero coupon T-notes (US Treasury Strip) 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 may not accurately predict the value ultimately realized by the employees who receive the awards, and the ultimate value 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 models for the estimated payout level of TSRIs were as follows:

	TSRIs
Year Granted	2012			2011			2010
Assumptions used:
Risk-free interest rate	0.4		%	0.6		%	0.6		%
Dividend yield	2.6		%	1.8		%	1.8		%
Volatility factor	34		%	33		%	32		%
Expected life (years)	3			3			3
Grant-date fair value of underlying Occidental common stock	$	84.57		$	102.97		$	84.29

A summary of Occidental’s unvested TSRIs as of December 31, 2012 and changes during the year ended December 31, 2012 is presented below:

	TSRIs
	Awards (000’s)		Weighted-Average Grant-Date Fair Value of Occidental Stock
Unvested at January 1 (a)	1,865		$	78.67
Granted (a)	453		$	84.57
Vested (b)	(388	)	$	77.00
Forfeitures	—		$	—
Unvested at December 31 (a)	1,930		$	80.39

(a) Unvested awards and award grants are presented at the target or mid-point payouts.

(b) The payout at vesting was 150 percent of the target for TSRIs.

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NOTE 13 RETIREMENT AND POSTRETIREMENT BENEFIT PLANS

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

DEFINED CONTRIBUTION PLANS

All domestic employees and certain foreign national employees are eligible to participate in one or more of the defined contribution retirement or savings plans that provide for periodic contributions by Occidental based on plan-specific criteria, such as base pay, age, level and employee contributions. Certain salaried employees participate in a supplemental retirement plan that restores benefits lost due to governmental limitations on qualified retirement benefits. The accrued liabilities for the supplemental retirement plan were $145 million and $126 million as of December 31, 2012 and 2011, respectively, and Occidental expensed $137 million in 2012, $110 million in 2011 and $101 million in 2010 under the provisions of these defined contribution and supplemental retirement plans.

DEFINED BENEFIT PLANS

Participation in defined benefit plans is limited and approximately 1,000 domestic and 1,600 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.

POSTRETIREMENT AND OTHER BENEFIT PLANS

Occidental provides medical and dental benefits and life insurance coverage for certain active, retired and disabled employees and their eligible dependents. Occidental generally funds the benefits as they are paid during the year. These benefit costs, including the postretirement costs, were approximately $218 million in 2012, $194 million in 2011 and $180 million in 2010.

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OBLIGATIONS AND FUNDED STATUS

The following tables show the amounts recognized in the consolidated balance sheets of Occidental related to its pension and postretirement benefit plans and their funding status, obligations and plan asset fair values (in millions):

	Pension Benefits						Postretirement Benefits
As of December 31,	2012			2011			2012			2011
Amounts recognized in the consolidated balance sheet:
Other assets	$	24		$	24		$	—		$	—
Accrued liabilities	(4		)	(5		)	(59		)	(47		)
Deferred credits and other liabilities — other	(136		)	(136		)	(1,068		)	(1,045		)
	$	(116	)	$	(117	)	$	(1,127	)	$	(1,092	)
AOCI included the following after-tax balances:
Net loss	$	134		$	146		$	324		$	331
Prior service cost	1			2			2			2
	$	135		$	148		$	326		$	333
For the years ended December 31,
Changes in benefit obligation:
Benefit obligation — beginning of year	$	592		$	615		$	1,092		$	991
Service cost — benefits earned during the period	13			12			25			22
Interest cost on projected benefit obligation	27			29			42			45
Actuarial loss	46			49			26			81
Foreign currency exchange rate (gain) loss	2			(5		)	—			—
Benefits paid	(57		)	(51		)	(58		)	(47		)
Settlements	(8		)	(57		)	—			—
Benefit obligation — end of year	$	615		$	592		$	1,127		$	1,092
Changes in plan assets:
Fair value of plan assets — beginning of year	$	475		$	495		$	—		$	—
Actual return on plan assets	61			13			—			—
Foreign currency exchange rate gain (loss)	(3		)	(3		)	—			—
Employer contributions	31			78			—			—
Benefits paid	(57		)	(51		)	—			—
Settlements	(8		)	(57		)	—			—
Fair value of plan assets — end of year	$	499		$	475		$	—		$	—
Unfunded status:	$	(116	)	$	(117	)	$	(1,127	)	$	(1,092	)

The following table sets forth details of the obligations and assets of Occidental's defined benefit pension plans (in millions):

	Accumulated Benefit Obligation in Excess of Plan Assets				Plan Assets in Excess of Accumulated Benefit Obligation
As of December 31, (in millions)	2012		2011		2012		2011
Projected Benefit Obligation	$	305	$	361	$	310	$	231
Accumulated Benefit Obligation	$	278	$	334	$	305	$	227
Fair Value of Plan Assets	$	171	$	226	$	328	$	249

Occidental does not expect any plan assets to be returned during 2013.

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COMPONENTS OF NET PERIODIC BENEFIT COST

The following table sets forth the components of net periodic benefit costs (in millions):

	Pension Benefits									Postretirement Benefits
For the years ended December 31, (in millions)	2012			2011			2010			2012		2011		2010
Net periodic benefit costs:
Service cost — benefits earned during the period	$	13		$	12		$	16		$	25	$	22	$	19
Interest cost on benefit obligation	27			29			30			42		45		44
Expected return on plan assets	(31		)	(33		)	(31		)	—		—		—
Recognized actuarial loss	19			13			15			37		31		27
Other costs and adjustments	17			—			10			1		1		1
Net periodic benefit cost	$	45		$	21		$	40		$	105	$	99	$	91

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 $17 million and $0, respectively. The estimated net loss and prior service cost for the defined benefit postretirement plans that will be amortized from AOCI into net periodic benefit cost over the next fiscal year are $37 million and $1 million, respectively.

ADDITIONAL INFORMATION

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
For the years ended December 31,	2012		2011		2012		2011
Benefit Obligation Assumptions:
Discount rate	3.59	%	4.12	%	3.89	%	4.12	%
Rate of compensation increase	4.00	%	4.00	%	—		—
Net Periodic Benefit Cost Assumptions:
Discount rate	4.12	%	4.74	%	4.12	%	4.74	%
Assumed long term rate of return on assets	6.50	%	6.50	%	—		—
Rate of compensation increase	4.00	%	4.00	%	—		—

For domestic pension plans and postretirement benefit plans, Occidental based the discount rate on the Aon/Hewitt AA-AAA Universe yield curve in 2012 and 2011. 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. Occidental considers historical returns and correlation of equities and fixed-income securities and current market factors such as inflation and interest rates.

For pension plans outside the United States, Occidental based its discount rate on rates indicative of government or investment grade corporate debt in the applicable country, taking into account hyperinflationary environments when necessary. The discount rates used for the foreign pension plans ranged from 1.5 percent to 10.0 percent at both December 31, 2012 and 2011. The average rate of increase in future compensation levels ranged from 1.5 percent to 10.0 percent in 2012, depending on local economic conditions. The expected long-term rate of return on plan assets was 6.5 percent and 5.8 percent in excess of local inflation in 2012 and 2011, respectively.

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 healthcare cost trend rates projected at an assumed U.S. Consumer Price Index (CPI) increase of 2.39 percent and 2.04 percent as of December 31, 2012 and 2011, respectively. Since 1993, participants other than certain union employees have paid for all medical cost increases in excess of increases in the CPI. For those union employees, Occidental projected that healthcare cost trend rates would decrease 0.5 percent per year from 8.5 percent in 2012 until they reach 6.0 percent in 2017, and remain at 6.0 percent thereafter. A 1-percent increase or a 1-percent decrease in these assumed healthcare cost trend rates would result in an increase of $44 million or a reduction of $37 million, respectively, in the postretirement benefit obligation as of December 31, 2012. The annual service and interest 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 assets and liabilities.

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FAIR VALUE OF PENSION PLAN ASSETS

Occidental employs a total return investment approach that uses a diversified blend of equity and fixed-income investments to optimize 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 investments across the spectrum of asset classes. 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 with the goals of enhancing long-term returns and improving portfolio diversification. The target allocation of plan assets is 60 percent equity securities and 40 percent debt securities. Investment performance is measured and monitored on an ongoing basis through quarterly investment portfolio and manager guideline compliance reviews, annual liability measurements and periodic studies.

The fair values of Occidental’s pension plan assets by asset category are as follows (in millions):

	Fair Value Measurements at December 31, 2012 Using
Description	Level 1		Level 2		Level 3		Total
Asset Class:
U.S. government securities	$	24	$	—	$	—	$	24
Corporate bonds (a)	—		83		—		83
Common/collective trusts (b)	—		11		—		11
Mutual funds:
Bond funds	84		—		—		84
Blend funds	106		—		—		106
Value and growth funds	5		—		—		5
Common and preferred stocks (c)	146		—		—		146
Other	—		35		11		46
Total pension plan assets (d)	$	365	$	129	$	11	$	505

	Fair Value Measurements at December 31, 2011 Using
Description	Level 1		Level 2		Level 3		Total
Asset Class:
U.S. government securities	$	22	$	—	$	—	$	22
Corporate bonds (a)	—		83		—		83
Common/collective trusts (b)	—		14		—		14
Mutual funds:
Bond funds	84		—		—		84
Blend funds	97		—		—		97
Value and growth funds	5		—		—		5
Common and preferred stocks (c)	131		—		—		131
Other	—		34		12		46
Total pension plan assets (d)	$	339	$	131	$	12	$	482

(a) This category represents investment grade bonds of U.S. and non-U.S. issuers from diverse industries.

(b) This category includes investment funds that primarily invest in U.S. and non-U.S. common stocks and fixed-income securities.

(c) This category represents direct investments in common and preferred stocks from diverse U.S. and non-U.S. industries.

(d) Amounts exclude net payables of approximately $6 million and $7 million as of December 31, 2012 and 2011, respectively.

The activity during the years ended December 31, 2012 and 2011 for the assets using Level 3 fair value measurements was insignificant.

Occidental expects to contribute $5 million in cash to its defined benefit pension plans during 2013.

67

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
2013	$	40	$	50
2014	$	44	$	51
2015	$	41	$	52
2016	$	46	$	53
2017	$	42	$	54
2018 — 2022	$	230	$	294

NOTE 14 INVESTMENTS AND RELATED-PARTY TRANSACTIONS

As of December 31, 2012 and 2011, investments in unconsolidated entities comprised $1.9 billion and $2.1 billion of equity-method investments, respectively.

EQUITY INVESTMENTS

As of December 31, 2012, Occidental’s equity investments consisted mainly of a 35-percent interest in the general partner of Plains Pipeline, a 24.5-percent interest in the stock of Dolphin Energy, and various other partnerships and joint ventures. Equity investments paid dividends of $526 million, $349 million and $217 million to Occidental in 2012, 2011 and 2010, respectively. As of December 31, 2012, cumulative undistributed earnings of equity-method investees since their respective acquisitions were approximately $240 million. As of December 31, 2012, Occidental's investments in equity investees exceeded the underlying equity in net assets by $1.1 billion, of which $1 billion represented goodwill and the remainder comprised intangibles amortized over their estimated useful lives.

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)	2012		2011		2010
Revenues	$	2,667	$	2,439	$	1,759
Costs and expenses	2,310		2,046		1,482
Net income	$	357	$	393	$	277
As of December 31, (in millions)	2012		2011
Current assets	$	2,065	$	2,230
Non-current assets	$	5,104	$	4,381
Current liabilities	$	1,774	$	1,532
Long-term debt	$	2,250	$	2,305
Other non-current liabilities	$	241	$	168
Stockholders’ equity	$	2,904	$	2,606

Occidental’s investment in Dolphin, which was acquired in 2002, consists of two separate economic interests through which Occidental owns (i) a 24.5-percent undivided interest in the operations under an agreement which is proportionately consolidated in the financial statements; and (ii) a 24.5-percent interest in the stock of Dolphin Energy, which is accounted for as an equity investment.

During 2010, Occidental had a 50-percent joint interest in EHP, which was accounted for as an equity method investment. On December 31, 2010, Occidental completed its acquisition of the remaining 50-percent interest, bringing its total ownership to 100 percent. EHP was consolidated in Occidental's balance sheet as of December 31, 2010.

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RELATED-PARTY TRANSACTIONS

Occidental from time to time purchases oil, NGLs, power, steam and chemicals from and sells oil, NGLs, gas, chemicals and power to certain of its equity investees at market-related prices. During 2012, 2011 and 2010, Occidental entered into the following related-party transactions and had the following amounts due from or to its related parties:

December 31, (in millions)	2012		2011		2010
Purchases (a)	$	8	$	10	$	153
Sales (b)	$	419	$	392	$	440
Services	$	17	$	10	$	2
Advances and amounts due from	$	25	$	32	$	135
Amounts due to	$	129	$	21	$	383

(a) In 2010, purchases from EHP accounted for 90 percent of total purchases.

(b) In 2012, 2011 and 2010, sales of Occidental-produced oil and NGLs to Plains Pipeline accounted for 80 percent, 76 percent and 50 percent of these totals, respectively. Additionally, Occidental conducts marketing and trading activities with Plains Pipeline for oil and NGLs. These transactions are reported in Occidental's income statement on a net margin basis. The sales amounts above include the net margins on such transactions, which were negligible. In 2012 and 2011, sales to Dolphin Energy accounted for 12 percent and 16 percent, of total sales, respectively. In 2010, sales to EHP and Dolphin Energy accounted for 44 percent of total sales.

NOTE 15 FAIR VALUE MEASUREMENTS

FAIR VALUES – RECURRING

The following tables provide fair value measurement information for assets and liabilities that are measured on a recurring basis as of December 31, 2012 and 2011 (in millions):

	Fair Value Measurements at December 31, 2012 Using						Netting and Collateral (a)			Total Fair Value
Description	Level 1		Level 2		Level 3
Assets:
Commodity derivatives	$	107	$	312	$	—	$	(301	)	$	118
Liabilities:
Commodity derivatives	$	99	$	398	$	—	$	(371	)	$	126

	Fair Value Measurements at December 31, 2011 Using						Netting and Collateral (a)			Total Fair Value
Description	Level 1		Level 2		Level 3
Assets:
Commodity derivatives	$	310	$	640	$	—	$	(758	)	$	192
Liabilities:
Commodity derivatives	$	311	$	652	$	—	$	(782	)	$	181

(a) Represents the impact of netting assets, liabilities and collateral when a legal right of offset exists.

69

FAIR VALUES – NONRECURRING

Occidental performed impairment tests with respect to its proved and unproved properties due to the negative revisions to certain of its natural gas reserves and the continued deterioration of natural gas prices. The impairment tests, including the fair value estimation, incorporate a number of assumptions involving expectations of future cash flows. These assumptions include estimates of future product prices, which Occidental bases on forward price curves and, where applicable, contractual prices, estimates of oil and gas reserves, estimates of future expected operating and development costs and appropriate discount rates.

In 2012, Occidental recorded pre-tax impairment charges of $1.7 billion, almost all of which were for certain assets in Midcontinent, over 90 percent of which were related to natural gas properties, which were acquired more than four years ago on average. These properties were impacted by persistently low natural gas prices in the United States changing management's development plans and negative reserve revisions due to recent well performance. In 2010, Occidental recorded a pre-tax impairment charge of $275 million, predominantly of gas properties in the Rocky Mountain region. Occidental used the income approach to measure the fair value of these properties, using inputs categorized as Level 3 in the fair value hierarchy.

FINANCIAL INSTRUMENTS FAIR VALUE

The carrying amounts of cash and cash equivalents and other on-balance-sheet financial instruments, other than fixed-rate debt, approximate fair value. The cost, if any, to terminate off-balance-sheet financial instruments is not significant.

NOTE 16 INDUSTRY SEGMENTS AND GEOGRAPHIC AREAS

Occidental conducts its continuing operations through three segments: (1) oil and gas; (2) chemical; and (3) midstream and marketing. The oil and gas segment explores for, develops and produces oil and condensate, NGLs, and natural gas. The chemical segment mainly manufactures and markets basic chemicals and vinyls. The midstream and marketing segment gathers, processes, transports, stores, purchases and markets oil, condensate, NGLs, natural gas, CO₂ and power. It also trades around its assets, including transportation and storage capacity, and trades oil, NGLs, gas and other commodities. The segment also invests in entities that conduct similar activities.

Earnings of industry segments and geographic areas exclude income taxes, interest income, interest expense, environmental remediation expenses, unallocated corporate expenses and discontinued operations, but include gains and losses from dispositions of segment and geographic area assets and income from the segments' equity investments. Intersegment sales eliminate upon consolidation and are generally made at prices approximating those that the selling entity would be able to obtain in third-party transactions.

Identifiable assets are those assets used in the operations of the segments. Corporate assets consist of cash, certain corporate receivables and PP&E, and an investment in the Joslyn, Canada oil sands project.

70

Industry Segments
In millions	Oil and Gas			Chemical			Midstream and Marketing			Corporate and Eliminations				Total
YEAR ENDED DECEMBER 31, 2012
Net sales	$	18,906	(a)	$	4,580	(b)	$	1,399	(c)	$	(713	)		$	24,172
Pretax operating profit (loss)	$	7,095	(d)	$	720		$	439		$	(501	)	(f,h)	$	7,753
Income taxes	—			—			—			(3,118		)	(g,h)	(3,118		)
Discontinued operations, net	—			—			—			(37		)		(37		)
Net income (loss) attributable to common stock	$	7,095		$	720		$	439		$	(3,656	)		$	4,598
Investments in unconsolidated entities	$	113		$	108		$	1,662		$	11			$	1,894
Property, plant and equipment additions, net (i)	$	8,282		$	365		$	1,612		$	91			$	10,350
Depreciation, depletion and amortization	$	3,933		$	345		$	206		$	27			$	4,511
Total assets	$	44,004		$	3,854		$	12,762		$	3,590			$	64,210
YEAR ENDED DECEMBER 31, 2011
Net sales	$	18,419	(a)	$	4,815	(b)	$	1,447	(c)	$	(742	)		$	23,939
Pretax operating profit (loss)	$	10,241	(d)	$	861		$	448		$	(709	)	(f,h)	$	10,841		(d)
Income taxes	—			—			—			(4,201		)	(g,h)	(4,201		)
Discontinued operations, net	—			—			—			131				131
Net income (loss) attributable to common stock	$	10,241	(d)	$	861		$	448		$	(4,779	)		$	6,771
Investments in unconsolidated entities	$	128		$	121		$	1,812		$	11			$	2,072
Property, plant and equipment additions, net (i)	$	6,192		$	241		$	1,120		$	51			$	7,604
Depreciation, depletion and amortization	$	3,064		$	330		$	173		$	24			$	3,591
Total assets	$	38,967		$	3,754		$	11,962		$	5,361			$	60,044
YEAR ENDED DECEMBER 31, 2010
Net sales	$	14,276	(a)	$	4,016	(b)	$	1,471	(c)	$	(718	)		$	19,045
Pretax operating profit (loss)	$	7,151	(d,e)	$	438		$	472		$	(497	)	(f,h)	$	7,564		(d,e)
Income taxes	—			—			—			(2,995		)	(g,h)	(2,995		)
Discontinued operations, net	—			—			—			(39		)		(39		)
Net income (loss) attributable to common stock	$	7,151	(d,e)	$	438		$	472		$	(3,531	)		$	4,530		(e)
Investments in unconsolidated entities	$	123		$	135		$	1,770		$	11			$	2,039
Property, plant and equipment additions, net (i)	$	3,211		$	248		$	537		$	38			$	4,034
Depreciation, depletion and amortization	$	2,668		$	321		$	142		$	22			$	3,153
Total assets	$	31,855		$	3,755		$	10,445		$	6,377		(j)	$	52,432
(See footnotes on next page)

71

Footnotes:

(a) Oil sales represented approximately 90 percent, 87 percent and 86 percent of the oil and gas segment net sales for the years ended December 31, 2012, 2011 and 2010, respectively.

(b) Net sales for the chemical segment comprised the following products:

	Basic Chemicals	Vinyls	Other Chemicals
Year ended December 31, 2012	57%	40%	3%
Year ended December 31, 2011	58%	39%	3%
Year ended December 31, 2010	57%	40%	3%

(c) Net sales for the midstream and marketing segment comprised the following:

	Gas Processing	Power	Marketing, Trading, Transportation and other
Year ended December 31, 2012	59%	20%	21%
Year ended December 31, 2011	64%	27%	9%
Year ended December 31, 2010	52%	27%	21%

(d) The 2012 amount includes pre-tax charges of $1.7 billion for the impairment of domestic gas assets and related items. The 2011 amount includes pre-tax charges of $35 million related to exploration write-offs in Libya and $29 million related to a Colombian net worth tax, and a pre-tax gain for the sale of an interest in a Colombian pipeline of $22 million. The 2010 amount includes a $275 million pre-tax charge for asset impairments, predominantly of gas properties in the Rocky Mountain region.  

(e) Includes amounts attributable to common stock after deducting a noncontrolling interest amount of $72 million.

(f) Includes unallocated net interest expense, administration expense, environmental remediation and other pre-tax items noted in footnote (h) below.

(g) Includes all foreign and domestic income taxes from continuing operations.

(h) Includes the following significant items affecting earnings for the years ended December 31:

Benefit (Charge)  (In millions)	2012			2011			2010
CORPORATE
Pre-tax operating profit (loss)
Premium on debt extinguishments	$	—		$	(163	)	$	—
Litigation reserves	(20		)	—			—
	$	(20	)	$	(163	)	$	—
Income taxes
State income tax charge	$	—		$	(33	)	$	—
Foreign tax credit carryforwards	—			—			80
Tax effect of pre-tax adjustments *	636			50			100
	$	636		$	17		$	180

* Amounts represent the tax effect of all pre-tax adjustments listed, as well as those in footnote (d).

(i) Includes capital expenditures and capitalized interest, but excludes purchases of assets, net. Also includes amounts attributable to the noncontrolling interest in a Colombian subsidiary for 2010.

(j) Includes Argentine assets, which were classified as held for sale.

GEOGRAPHIC AREAS

In millions

	Net sales (a)						Property, plant and equipment, net
For the years ended December 31,	2012		2011		2010		2012		2011		2010
United States	$	15,359	$	15,040	$	12,151	$	40,786	$	36,283	$	28,571
Foreign
Qatar	3,356		3,432		2,677		2,676		2,735		2,823
Oman	2,578		2,500		1,666		2,353		2,143		1,967
Colombia	1,027		1,054		999		1,041		854		715
Yemen	407		907		766		199		245		347
Bahrain	215		187		100		688		477		222
United Arab Emirates	—		—		—		2,104		971		1
Other Foreign	1,230		819		686		2,217		1,976		1,890
Total Foreign	8,813		8,899		6,894		11,278		9,401		7,965
Total	$	24,172	$	23,939	$	19,045	$	52,064	$	45,684	$	36,536

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

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2012 Quarterly Financial Data(Unaudited)	Occidental Petroleum Corporation and Subsidiaries
In millions, except per-share amounts

Three months ended	March 31			June 30			September 30			December 31
Segment net sales
Oil and gas	$	4,902		$	4,495		$	4,635		$	4,874
Chemical	1,148			1,172			1,119			1,141
Midstream, marketing and other	393			262			389			355
Eliminations	(175		)	(161		)	(178		)	(199		)
Net sales	$	6,268		$	5,768		$	5,965		$	6,171
Gross profit	$	3,144		$	2,541		$	2,617		$	2,842
Segment earnings
Oil and gas	$	2,504		$	2,043		$	2,026		$	522		(a)
Chemical	184			194			162			180
Midstream, marketing and other	131			77			156			75
	2,819			2,314			2,344			777
Unallocated corporate items
Interest expense, net	(28		)	(25		)	(34		)	(30		)
Income taxes	(1,139		)	(875		)	(855		)	(249		)
Other	(92		)	(82		)	(76		)	(134		)
Income from continuing operations	1,560			1,332			1,379			364
Discontinued operations, net	(1		)	(4		)	(4		)	(28		)
Net income attributable to common stock	$	1,559		$	1,328		$	1,375		$	336
Basic earnings per common share
Income from continuing operations	$	1.92		$	1.64		$	1.70		$	0.45
Discontinued operations, net	—			—			(0.01		)	(0.03		)
Basic earnings per common share	$	1.92		$	1.64		$	1.69		$	0.42
Diluted earnings per common share
Income from continuing operations	$	1.92		$	1.64		$	1.70		$	0.45
Discontinued operations, net	—			—			(0.01		)	(0.03		)
Diluted earnings per common share	$	1.92		$	1.64		$	1.69		$	0.42
Dividends per common share	$	0.54		$	0.54		$	0.54		$	0.54
Market price per common share
High	$	106.68		$	98.24		$	93.60		$	87.39
Low	$	91.85		$	76.59		$	82.25		$	72.43

(a) Includes fourth quarter pre-tax charges of $1.7 billion.

73

2011 Quarterly Financial Data(Unaudited)	Occidental Petroleum Corporation and Subsidiaries
In millions, except per-share amounts

Three months ended	March 31				June 30			September 30			December 31
Segment net sales
Oil and gas	$	4,367			$	4,591		$	4,677		$	4,784
Chemical	1,165				1,325			1,231			1,094
Midstream, marketing and other	412				441			256			338
Eliminations	(218		)		(184		)	(158		)	(182		)
Net sales	$	5,726			$	6,173		$	6,006		$	6,034
Gross profit	$	3,049			$	3,291		$	2,975		$	3,050
Segment earnings
Oil and gas	$	2,468			$	2,624		$	2,612		$	2,537
Chemical	219				253			245			144
Midstream, marketing and other	114				187			77			70
	2,801				3,064			2,934			2,751
Unallocated corporate items
Interest expense, net	(214		)	(a)	(22		)	(23		)	(25		)
Income taxes	(1,054		)		(1,111		)	(1,087		)	(949		)
Other	(128		)		(112		)	(49		)	(136		)
Income from continuing operations	1,405				1,819			1,775			1,641
Discontinued operations, net	144				(2		)	(4		)	(7		)
Net income attributable to common stock	$	1,549			$	1,817		$	1,771		$	1,634
Basic earnings per common share
Income from continuing operations	$	1.72			$	2.23		$	2.18		$	2.02
Discontinued operations, net	0.18				—			(0.01		)	(0.01		)
Basic earnings per common share	$	1.90			$	2.23		$	2.17		$	2.01
Diluted earnings per common share
Income from continuing operations	$	1.72			$	2.23		$	2.18		$	2.02
Discontinued operations, net	0.18				—			(0.01		)	(0.01		)
Diluted earnings per common share	$	1.90			$	2.23		$	2.17		$	2.01
Dividends per common share	$	0.46			$	0.46		$	0.46		$	0.46
Market price per common share
High	$	107.56			$	117.89		$	109.08		$	101.65
Low	$	93.25			$	95.67		$	69.90		$	66.36

(a) Includes a pre-tax charge of $163 million related to the premium on debt extinguishment.

74

Supplemental Oil and Gas Information(Unaudited)

The following tables set forth Occidental’s net interests in quantities of proved developed and undeveloped reserves of oil (including condensate), NGLs and natural gas and changes in such quantities. Reserves are stated net of applicable royalties. Estimated reserves include Occidental's economic interests under production sharing contracts (PSCs) and other similar economic arrangements. In addition, discussions of oil and gas production or volumes, in general, refer to sales volumes unless the context requires or it is indicated otherwise.

Oil Reserves
In millions of barrels (MMbbl)
	United		Latin		Middle East/
	States		America (a,b)		North Africa (c)		Total
PROVED DEVELOPED AND UNDEVELOPED RESERVES
Balance at December 31, 2009	1,385		95		494		1,974
Revisions of previous estimates	—		2		(34	)	(32	)
Improved recovery	82		9		42		133
Extensions and discoveries	1		—		—		1
Purchases of proved reserves	72		—		30		102
Sales of proved reserves (d)	—		(3	)	—		(3	)
Production	(80	)	(13	)	(70	)	(163	)
Balance at December 31, 2010	1,460		90		462		2,012
Revisions of previous estimates	(71	)	(3	)	(60	)	(134	)
Improved recovery	135		16		50		201
Extensions and discoveries	8		4		3		15
Purchases of proved reserves	78		—		—		78
Sales of proved reserves	—		—		—		—
Production	(84	)	(11	)	(69	)	(164	)
Balance at December 31, 2011	1,526		96		386		2,008
Revisions of previous estimates	(70	)	4		(3	)	(69	)
Improved recovery	143		7		30		180
Extensions and discoveries	7		—		27		34
Purchases of proved reserves	54		—		—		54
Sales of proved reserves	—		—		—		—
Production	(93	)	(11	)	(67	)	(171	)
Balance at December 31, 2012	1,567		96		373		2,036
PROVED DEVELOPED RESERVES
December 31, 2009	1,131		71		378		1,580
December 31, 2010	1,126		69		366		1,561
December 31, 2011	1,146		69		317		1,532
December 31, 2012 (e)	1,156		82		295		1,533
PROVED UNDEVELOPED RESERVES
December 31, 2009	254		24		116		394
December 31, 2010	334		21		96		451
December 31, 2011	380		27		69		476
December 31, 2012 (f)	411		14		78		503

(a) Proved reserves as of December 31, 2009 include proved oil reserves related to the noncontrolling interest of a Colombian subsidiary. On December 31, 2010, Occidental restructured its Colombian operations to take a direct working interest in the related assets. As a result, the December 31, 2010, 2011 and 2012 proved reserves amounts exclude the noncontrolling interest.

(b) Excludes proved oil reserves from the Argentine operations sold in February 2011 and classified as discontinued operations of 166 MMbbl and 108 MMbbl as of December 31, 2010 and 2009, respectively.  

(c) A substantial majority of the proved reserve amounts relate to PSCs and other similar economic arrangements.

(d) Represents the change to no longer include the Colombian noncontrolling interest.

(e) Approximately 8 percent of the proved developed reserves at December 31, 2012 are nonproducing, the majority of which are located in the United States.

(f) The amount of Occidental's proved undeveloped reserves that are not expected to be developed within five years from the date initially recorded was insignificant.

75

NGL Reserves
In millions of barrels (MMbbl)
	United		Latin	Middle East/
	States		America	North Africa (a)		Total
PROVED DEVELOPED AND UNDEVELOPED RESERVES
Balance at December 31, 2009	221		—	68		289
Revisions of previous estimates	8		—	(2	)	6
Improved recovery	16		—	—		16
Extensions and discoveries	—		—	—		—
Purchases of proved reserves	11		—	—		11
Sales of proved reserves	—		—	—		—
Production	(19	)	—	(5	)	(24	)
Balance at December 31, 2010	237		—	61		298
Revisions of previous estimates	—		—	(2	)	(2	)
Improved recovery	10		—	—		10
Extensions and discoveries	1		—	—		1
Purchases of proved reserves	2		—	—		2
Sales of proved reserves	—		—	—		—
Production	(25	)	—	(4	)	(29	)
Balance at December 31, 2011	225		—	55		280
Revisions of previous estimates	1		—	—		1
Improved recovery	16		—	—		16
Extensions and discoveries	—		—	64		64
Purchases of proved reserves	1		—	—		1
Sales of proved reserves	—		—	—		—
Production	(27	)	—	(3	)	(30	)
Balance at December 31, 2012	216		—	116		332
PROVED DEVELOPED RESERVES
December 31, 2009	155		—	68		223
December 31, 2010	163		—	61		224
December 31, 2011	165		—	55		220
December 31, 2012 (b)	167		—	53		220
PROVED UNDEVELOPED RESERVES
December 31, 2009	66		—	—		66
December 31, 2010	74		—	—		74
December 31, 2011	60		—	—		60
December 31, 2012 (c)	49		—	63		112

(a) A substantial portion of proved reserve amounts relate to PSCs and other similar economic arrangements.

(b) Approximately 5 percent of the proved developed reserves at December 31, 2012 are nonproducing, the majority of which are located in the United States.

(c) The amount of Occidental's proved undeveloped reserves that are not expected to be developed within five years from the date initially recorded was insignificant.

76

Gas Reserves
In billions of cubic feet (Bcf)
	United		Latin		Middle East/
	States		America (a)		North Africa (b)		Total
PROVED DEVELOPED AND UNDEVELOPED RESERVES
Balance at December 31, 2009	2,799		53		2,175		5,027
Revisions of previous estimates	(55	)	(1	)	(60	)	(116	)
Improved recovery	344		10		87		441
Extensions and discoveries	7		—		12		19
Purchases of proved reserves	186		—		—		186
Sales of proved reserves	—		—		—		—
Production	(247	)	(6	)	(166	)	(419	)
Balance at December 31, 2010	3,034		56		2,048		5,138
Revisions of previous estimates	(369	)	(19	)	(78	)	(466	)
Improved recovery	222		2		95		319
Extensions and discoveries	35		—		16		51
Purchases of proved reserves	728		—		—		728
Sales of proved reserves	—		—		—		—
Production	(285	)	(6	)	(156	)	(447	)
Balance at December 31, 2011	3,365		33		1,925		5,323
Revisions of previous estimates	(748	)	—		62		(686	)
Improved recovery	317		11		34		362
Extensions and discoveries	19		—		784		803
Purchases of proved reserves	236		—		—		236
Sales of proved reserves	—		—		—		—
Production	(300	)	(5	)	(165	)	(470	)
Balance at December 31, 2012	2,889		39		2,640		5,568
PROVED DEVELOPED RESERVES
December 31, 2009	1,931		51		1,759		3,741
December 31, 2010	2,007		50		1,665		3,722
December 31, 2011	2,365		32		1,555		3,952
December 31, 2012 (c)	2,121		36		1,816		3,973
PROVED UNDEVELOPED RESERVES
December 31, 2009	868		2		416		1,286
December 31, 2010	1,027		6		383		1,416
December 31, 2011	1,000		1		370		1,371
December 31, 2012 (d)	768		3		824		1,595

(a) Excludes proved natural gas reserves from the Argentine operations sold in February 2011 and classified as discontinued operations of 182 Bcf and 130 Bcf as of December 31, 2010 and 2009, respectively.

(b) A substantial majority of proved reserve amounts relate to PSCs and other similar economic arrangements.

(c) Approximately 3 percent of the proved developed reserves at December 31, 2012 are nonproducing, the majority of which are located in the United States.

(d) The amount of Occidental's proved undeveloped reserves that are not expected to be developed within five years from the date initially recorded was insignificant.

77

Total Reserves
In millions of BOE (MMBOE) (a)
	United		Latin		Middle East/
	States		America(b,c)		North Africa (d)		Total
PROVED DEVELOPED AND UNDEVELOPED RESERVES
Balance at December 31, 2009	2,072		104		924		3,100
Revisions of previous estimates	(1	)	2		(46	)	(45	)
Improved recovery	156		11		57		224
Extensions and discoveries	2		—		2		4
Purchases of proved reserves	114		—		30		144
Sales of proved reserves(e)	—		(3	)	—		(3	)
Production	(140	)	(14	)	(103	)	(257	)
Balance at December 31, 2010	2,203		100		864		3,167
Revisions of previous estimates	(132	)	(7	)	(75	)	(214	)
Improved recovery	182		16		66		264
Extensions and discoveries	15		4		6		25
Purchases of proved reserves	201		—		—		201
Sales of proved reserves	—		—		—		—
Production	(156	)	(12	)	(99	)	(267	)
Balance at December 31, 2011	2,313		101		762		3,176
Revisions of previous estimates	(194	)	4		7		(183	)
Improved recovery	212		9		36		257
Extensions and discoveries	10		—		222		232
Purchases of proved reserves	94		—		—		94
Sales of proved reserves	—		—		—		—
Production	(170	)	(12	)	(98	)	(280	)
Balance at December 31, 2012	2,265		102		929		3,296
PROVED DEVELOPED RESERVES
December 31, 2009	1,608		80		739		2,427
December 31, 2010	1,624		78		705		2,407
December 31, 2011	1,707		74		631		2,412
December 31, 2012 (f)	1,677		88		651		2,416
PROVED UNDEVELOPED RESERVES
December 31, 2009	464		24		185		673
December 31, 2010	579		22		159		760
December 31, 2011	606		27		131		764
December 31, 2012 (g)	588		14		278		880

(a) Natural gas volumes have been converted to barrels of oil equivalent (BOE) based on energy content of six thousand cubic feet (Mcf) of gas to one barrel of oil. Barrels of oil equivalence does not necessarily result in price equivalence. The price of natural gas on a barrel of oil equivalent basis is currently substantially lower than the corresponding price for oil and has been similarly lower over the recent past. For example, in 2012, the average prices of West Texas Intermediate (WTI) oil and New York Mercantile Exchange (NYMEX) natural gas were $94.21 per barrel and $2.81 per Mcf, respectively, resulting in an oil to gas ratio of over 30.

(b) Proved reserves as of December 31, 2009 include proved oil reserves related to the noncontrolling interest of a Colombian subsidiary.

(c) Excludes proved reserves from the Argentine operations sold in February 2011 and classified as discontinued operations of 196 MMBOE and 130 MMBOE as of December 31, 2010 and 2009, respectively.

(d) A substantial majority of proved reserve amounts relate to PSCs and other similar economic arrangements.

(e) Represents the change to no longer include the Colombian noncontrolling interest.

(f) Approximately 6 percent of the proved developed reserves at December 31, 2012 are nonproducing, the majority of which are located in the United States.

(g) The amount of Occidental's proved undeveloped reserves that are not expected to be developed within five years from the date initially recorded was insignificant.

,

78

CAPITALIZED COSTS

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

	United			Latin				Middle East/
In millions	States			America				North Africa			Total
December 31, 2012
Proved properties	$	42,563		$	2,142			$	15,873		$	60,578
Unproved properties (a)	4,592			27				220			4,839
Total capitalized costs(b)	47,155			2,169				16,093			65,417
Accumulated depreciation, depletion and amortization	(13,432		)	(1,068		)		(8,582		)	(23,082		)
Net capitalized costs	$	33,723		$	1,101			$	7,511		$	42,335
December 31, 2011
Proved properties	$	36,123		$	1,861			$	13,839		$	51,823
Unproved properties (a)	4,675			—				184			4,859
Total capitalized costs(b)	40,798			1,861				14,023			56,682
Accumulated depreciation, depletion and amortization	(11,063		)	(951		)		(7,178		)	(19,192		)
Net capitalized costs	$	29,735		$	910			$	6,845		$	37,490
December 31, 2010
Proved properties	$	28,516		$	1,816			$	12,231		$	42,563
Unproved properties (a)	3,474			5				190			3,669
Total capitalized costs(b)	31,990			1,821				12,421			46,232
Accumulated depreciation, depletion and amortization	(9,321		)	(1,050		)		(5,960		)	(16,331		)
Net capitalized costs	$	22,669		$	771		(c)	$	6,461		$	29,901

(a) The 2012, 2011 and 2010 amounts primarily consist of Midcontinent and Other, Permian and California.

(b) Includes acquisition costs, development costs, capitalized interest and asset retirement obligations.

(c) Excludes Argentine net capitalized costs of $2.6 billion as of December 31, 2010.

COSTS INCURRED

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

	United		Latin			Middle East/
In millions	States		America			North Africa		Total
FOR THE YEAR ENDED DECEMBER 31, 2012
Property acquisition costs
Proved properties	$	1,689	$	—		$	14	$	1,703
Unproved properties	613		—			—		613
Exploration costs	539		1			114		654
Development costs	5,344		304			2,025		7,673
Costs incurred	$	8,185	$	305		$	2,153	$	10,643
FOR THE YEAR ENDED DECEMBER 31, 2011
Property acquisition costs
Proved properties	$	3,185	$	—		$	—	$	3,185
Unproved properties	1,311		—			32		1,343
Exploration costs	400		33			87		520
Development costs	4,100		214			1,495		5,809
Costs incurred	$	8,996	$	247		$	1,614	$	10,857
FOR THE YEAR ENDED DECEMBER 31, 2010
Property acquisition costs
Proved properties	$	2,084	$	—		$	63	$	2,147
Unproved properties	2,290		—			—		2,290
Exploration costs	177		13			126		316
Development costs	1,674		178			1,231		3,083
Costs incurred	$	6,225	$	191	(a)	$	1,420	$	7,836

(a) Includes exploration and development costs of $2 million and $5 million, respectively, in 2010 related to the noncontrolling interest in a Colombian subsidiary. Excludes Argentine costs incurred of $448 million.

79

RESULTS OF OPERATIONS

Occidental’s oil and gas producing activities for continuing operations, which exclude items such as asset dispositions, corporate overhead, interest and royalties, were as follows:

	United		Latin			Middle East/
In millions	States		America			North Africa		Total
FOR THE YEAR ENDED DECEMBER 31, 2012
Revenues (a)	$	10,379	$	1,085		$	7,486	$	18,950
Production costs (b)	2,963		165			1,061		4,189
Other operating expenses	723		43			224		990
Depreciation, depletion and amortization	2,412		117			1,404		3,933
Taxes other than on income	644		23			—		667
Asset impairments and related items	1,731		—			—		1,731
Exploration expenses	230		3			112		345
Pretax income	1,676		734			4,685		7,095
Income tax expense (c)	508		252			2,159		2,919
Results of operations	$	1,168	$	482		$	2,526	$	4,176
FOR THE YEAR ENDED DECEMBER 31, 2011
Revenues (a)	$	9,933	$	1,113		$	7,373	$	18,419
Production costs (b)	2,338		172			918		3,428
Other operating expenses	584		37			217		838
Depreciation, depletion and amortization	1,754		90			1,220		3,064
Taxes other than on income	567		23			—		590
Exploration expenses	200		2			56		258
Pretax income	4,490		789			4,962		10,241
Income tax expense (c)	1,419		270			2,145		3,834
Results of operations	$	3,071	$	519		$	2,817	$	6,407
FOR THE YEAR ENDED DECEMBER 31, 2010
Revenues (a)	$	7,578	$	1,046	(d)	$	5,621	$	14,245
Production costs (b)	1,757		167		(d)	698		2,622
Other operating expenses	432		15			208		655
Depreciation, depletion and amortization	1,412		122			1,134		2,668
Taxes other than on income	454		18			—		472
Asset impairments and related items	275		—			—		275
Exploration expenses	158		7			97		262
Pretax income	3,090		717			3,484		7,291
Income tax expense (c)	929		227			1,689		2,845
Results of operations	$	2,161	$	490	(d,e)	$	1,795	$	4,446

(a) Revenues are net of royalty payments.

(b) Production costs are the costs incurred in lifting the oil and gas to the surface and include gathering, primary processing, field storage and insurance on proved properties, but do not include DD&A, royalties, income taxes, interest, general and administrative and other expenses.

(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.

(d) Includes revenues of $129 million, production costs of $17 million, and results of operations of $72 million in 2010, related to the noncontrolling interest in a Colombian subsidiary.

(e) Excludes amounts from the Argentine operations sold in February 2011 and classified as discontinued operations.

80

RESULTS PER UNIT OF PRODUCTION FOR CONTINUING OPERATIONS

	United		Latin			Middle East/
	States		America			North Africa		Total
FOR THE YEAR ENDED DECEMBER 31, 2012
Revenue from each barrel of oil equivalent ($/bbl.) (a,b)	$	61.06	$	96.30		$	76.22	$	67.81
Production costs	17.43		14.64			10.80		14.99
Other operating expenses	4.25		3.82			2.28		3.54
Depreciation, depletion and amortization	14.19		10.38			14.30		14.07
Taxes other than on income	3.79		2.04			—		2.39
Asset impairments and related items	10.18		—			—		6.19
Exploration expenses	1.35		0.27			1.14		1.23
Pretax income	9.87		65.15			47.70		25.40
Income tax expense (c)	2.99		22.37			21.98		10.45
Results of operations	$	6.88	$	42.78		$	25.72	$	14.95
FOR THE YEAR ENDED DECEMBER 31, 2011
Revenue from each barrel of oil equivalent ($/bbl.) (a,b)	$	63.56	$	94.19		$	74.58	$	68.99
Production costs	14.96		14.56			9.29		12.84
Other operating expenses	3.74		3.13			2.20		3.14
Depreciation, depletion and amortization	11.22		7.62			12.34		11.48
Taxes other than on income	3.63		1.95			—		2.21
Exploration expenses	1.28		0.17			0.57		0.97
Pretax income	28.73		66.76			50.18		38.35
Income tax expense (c)	9.08		22.85			21.70		14.36
Results of operations	$	19.65	$	43.91		$	28.48	$	23.99
FOR THE YEAR ENDED DECEMBER 31, 2010
Revenue from each barrel of oil equivalent ($/bbl.) (a,b)	$	54.14	$	73.31		$	54.49	$	55.35
Production costs	12.55		11.70			6.77		10.19
Other operating expenses	3.09		1.05			2.02		2.55
Depreciation, depletion and amortization	10.09		8.55			10.99		10.37
Taxes other than on income	3.24		1.26			—		1.83
Asset impairments and related items	1.96		—			—		1.07
Exploration expenses	1.13		0.49			0.94		1.02
Pretax income	22.08		50.26			33.77		28.32
Income tax expense (c)	6.64		15.91			16.37		11.05
Results of operations	$	15.44	$	34.35	(d,e)	$	17.40	$	17.27

(a) Natural gas volumes have been converted to BOE based on energy content of six thousand cubic feet (Mcf) of gas to one barrel of oil. Barrels of oil equivalence does not necessarily result in price equivalence. The price of natural gas on a barrel of oil equivalent basis is currently substantially lower than the corresponding price for oil and has been similarly lower over the recent past. For example, in 2012, the average prices of WTI oil and NYMEX natural gas were $94.21 per barrel and $2.81 per Mcf, respectively, resulting in an oil to gas ratio of over 30.

(b) Revenues are net of royalty payments.

(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.

(d) Includes the noncontrolling interest in a Colombian subsidiary for 2010.

(e) Excludes amounts from the Argentine operations sold in February 2011 and classified as discontinued operations.

STANDARDIZED MEASURE, INCLUDING YEAR-TO-YEAR CHANGES THEREIN, OF DISCOUNTED FUTURE NET CASH FLOWS

For purposes of the following disclosures, future cash flows were computed by applying to Occidental's proved oil and gas reserves the unweighted arithmetic average of the first-day-of-the-month price for each month within the years ended December 31, 2012, 2011 and 2010, respectively, unless prices were defined by contractual arrangements, and exclude escalations based upon future conditions. The realized prices used to calculate future cash flows vary by producing area and market conditions. Future operating and capital costs were forecast using the current cost environment applied to expectations of future operating and development activities. 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 December 31, 2012, 2011 and 2010. Such assumptions, which are required by regulation, have not always proven accurate in the past. Other valid assumptions would give rise to substantially different results.

81

Standardized Measure of Discounted Future Net Cash Flows
In millions
	United			Latin			Middle East/
	States			America			North Africa			Total
AT DECEMBER 31, 2012
Future cash inflows	$	161,821		$	10,574		$	48,914		$	221,309
Future costs
Production costs and other operating expenses	(68,780		)	(3,562		)	(11,922		)	(84,264		)
Development costs (a)	(15,890		)	(541		)	(5,539		)	(21,970		)
Future income tax expense	(21,387		)	(2,023		)	(14,165		)	(37,575		)
Future net cash flows	55,764			4,448			17,288			77,500
Ten percent discount factor	(29,745		)	(1,812		)	(6,656		)	(38,213		)
Standardized measure of discounted future net cash flows	$	26,019		$	2,636		$	10,632		$	39,287
AT DECEMBER 31, 2011
Future cash inflows	$	171,456		$	8,494		$	43,715		$	223,665
Future costs
Production costs and other operating expenses	(69,404		)	(2,807		)	(8,926		)	(81,137		)
Development costs (a)	(13,660		)	(689		)	(3,407		)	(17,756		)
Future income tax expense	(26,175		)	(1,579		)	(15,374		)	(43,128		)
Future net cash flows	62,217			3,419			16,008			81,644
Ten percent discount factor	(32,835		)	(1,415		)	(5,127		)	(39,377		)
Standardized measure of discounted future net cash flows	$	29,382		$	2,004		$	10,881		$	42,267
AT DECEMBER 31, 2010
Future cash inflows	$	133,080		$	6,833		$	39,156		$	179,069
Future costs
Production costs and other operating expenses	(54,362		)	(2,828		)	(9,228		)	(66,418		)
Development costs (a)	(9,820		)	(458		)	(3,743		)	(14,021		)
Future income tax expense	(20,319		)	(1,036		)	(12,585		)	(33,940		)
Future net cash flows	48,579			2,511			13,600			64,690
Ten percent discount factor	(26,481		)	(1,044		)	(4,428		)	(31,953		)
Standardized measure of discounted future net cash flows	$	22,098		$	1,467		$	9,172		$	32,737

(a) Includes asset retirement costs.

Changes in the Standardized Measure of Discounted Future
Net Cash Flows From Proved Reserve Quantities
In millions
For the years ended December 31,	2012			2011			2010
Beginning of year	$	42,267		$	32,737		$	23,756
Sales and transfers of oil and gas produced, net of production costs and other operating expenses	(14,818		)	(15,243		)	(11,698		)
Net change in prices received per barrel, net of production costs and other operating expenses	(3,005		)	20,325			15,507
Extensions, discoveries and improved recovery, net of future production and development costs	5,625			6,152			4,485
Change in estimated future development costs	(7,330		)	(5,668		)	(2,747		)
Revisions of quantity estimates	(2,057		)	(3,518		)	(626		)
Development costs incurred during the period	7,700			5,797			3,101
Accretion of discount	5,203			4,014			2,843
Net change in income taxes	5,045			(4,776		)	(4,663		)
Purchases and sales of reserves in place, net	1,076			3,220			1,871
Changes in production rates and other	(419		)	(773		)	908
Net change	(2,980		)	9,530			8,981
End of year	$	39,287		$	42,267		$	32,737

82

Average Sales Prices

The following table sets forth, for each of the three years in the period ended December 31, 2012, Occidental’s approximate average sales prices in continuing operations.

			United		Latin		Middle East/
			States		America (a)		North Africa		Total
2012
Oil	—	Average sales price ($/bbl.)	$	93.72	$	98.35	$	108.76	$	99.87
NGLs	—	Average sales price ($/bbl.)	$	46.07	$	—	$	37.74	$	45.18
Gas	—	Average sales price ($/mcf.)	$	2.62	$	11.85	$	0.76	$	2.06
2011
Oil	—	Average sales price ($/bbl.)	$	92.80	$	97.16	$	104.34	$	97.92
NGLs	—	Average sales price ($/bbl.)	$	59.10	$	—	$	32.09	$	55.53
Gas	—	Average sales price ($/mcf.)	$	4.06	$	10.11	$	0.81	$	3.01
2010
Oil	—	Average sales price ($/bbl.)	$	73.79	$	75.29	$	76.67	$	75.16
NGLs	—	Average sales price ($/bbl.)	$	48.86	$	—	$	30.64	$	45.08
Gas	—	Average sales price ($/mcf.)	$	4.53	$	7.73	$	0.82	$	3.11

(a) Excludes average sales prices from Argentine operations sold in February 2011 and classified as discontinued operations and for 2010 includes the noncontrolling interest in a Colombian subsidiary.

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, 2012, Occidental’s net productive and dry–exploratory and development wells completed.

			United	Latin	Middle East/
			States	America (a)	North Africa	Total
2012
Oil	—	Exploratory	41.0	—	3.3	44.3
		Development	1,183.8	51.8	264.6	1,500.2
Gas	—	Exploratory	3.9	—	—	3.9
		Development	134.5	1.0	6.5	142.0
Dry	—	Exploratory	16.5	—	6.1	22.6
		Development	31.5	0.4	2.4	34.3
2011
Oil	—	Exploratory	17.7	1.8	2.6	22.1
		Development	834.0	57.9	189.3	1,081.2
Gas	—	Exploratory	3.2	—	2.5	5.7
		Development	143.1	—	1.1	144.2
Dry	—	Exploratory	13.0	—	1.4	14.4
		Development	9.3	—	1.2	10.5
2010
Oil	—	Exploratory	8.4	0.9	1.8	11.1
		Development	406.6	42.3	121.3	570.2
Gas	—	Exploratory	—	—	5.0	5.0
		Development	93.3	—	4.6	97.9
Dry	—	Exploratory	17.3	0.8	2.8	20.9
		Development	10.0	—	0.4	10.4

(a) Excludes for all years presented the exploratory and development wells completed by Argentine operations sold in February 2011 and classified as discontinued operations and for 2010 includes the noncontrolling interest in a Colombian subsidiary.

83

Productive Oil and Gas Wells

The following table sets forth, as of December 31, 2012, Occidental’s productive oil and gas wells (both producing and capable of production).

Wells at December 31, 2012 (a)			United States		Latin America		Middle East/ North Africa		Total
Oil	—	Gross (b)	27,030	(1,839)	1,338	—	3,036	(670)	31,404	(2,509)
		Net (c)	22,870	(1,449)	665	—	1,607	(322)	25,142	(1,771)
Gas	—	Gross (b)	6,743	(424)	30	—	131	(2)	6,904	(426)
		Net (c)	5,942	(352)	28	—	69	(2)	6,039	(354)

(a) The numbers in parentheses indicate the number of wells with multiple completions.

(b) The total number of wells in which interests are owned.

(c) The sum of fractional interests.

Participation in Exploratory and Development Wells Being Drilled

The following table sets forth, as of December 31, 2012, Occidental’s participation in exploratory and development wells being drilled.

Wells at December 31, 2012			United States	Latin America	Middle East/ North Africa	Total
Exploratory and development wells
	—	Gross	181	7	56	244
	—	Net	165	4	25	194

At December 31, 2012, Occidental was participating in 193 pressure-maintenance projects, mostly waterfloods, in the United States, 8 in Latin America and 33 in the Middle East/North Africa.

Oil and Gas Acreage

The following table sets forth, as of December 31, 2012, Occidental’s holdings of developed and undeveloped oil and gas acreage.

Thousands of acres at			United	Latin	Middle East/
December 31, 2012			States (a)	America	North Africa	Total
Developed (b)
	—	Gross (c)	8,373	121	1,233	9,727
	—	Net (d)	5,012	83	562	5,657
Undeveloped (e)
	—	Gross (c)	6,208	484	17,058	23,750
	—	Net (d)	3,042	363	15,102	18,507

(a) Includes approximately 2.1 million acres in California, the large majority of which are net fee mineral interests.

(b) Acres spaced or assigned to productive wells.

(c) Total acres in which interests are held.

(d) Sum of the fractional interests owned based on working interests, or interests under PSCs and other economic arrangements.

(e) 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.

Occidental’s investment in developed and undeveloped acreage comprises numerous concessions, blocks and leases. Work programs are designed to ensure that the exploration potential of any property is fully evaluated before expiration. In some instances, Occidental may elect to relinquish acreage in advance of the contractual expiration date if the evaluation process is complete and there is not a business basis for extension. In cases where additional time may be required to fully evaluate acreage, Occidental has generally been successful in obtaining extensions. Scheduled lease and concession expirations for undeveloped acreage over the next three years are not expected to have a material adverse impact on Occidental.

84

Oil, NGLs and Natural Gas Production and Sales Volumes Per Day

The following tables set forth the production and sales volumes of oil, NGLs and natural gas per day for each of the three years in the period ended December 31, 2012. The differences between the production and sales volumes per day are generally due to the timing of shipments at Occidental’s international locations where product is loaded onto tankers.

Production per Day	2012	2011	2010
United States
Oil (MBBL)
California	88	80	76
Permian	142	134	136
Midcontinent and Other	25	16	7
TOTAL	255	230	219
NGLs (MBBL)
California	17	15	16
Permian	39	38	29
Midcontinent and Other	17	16	7
TOTAL	73	69	52
Natural gas (MMCF)
California	256	260	280
Permian	155	157	199
Midcontinent and Other	410	365	198
TOTAL	821	782	677
Latin America (a)
Oil (MBBL) - Colombia (b)	29	29	37
Natural gas (MMCF) - Bolivia	13	15	16
Middle East/North Africa
Oil (MBBL)
Bahrain	4	4	3
Dolphin	8	9	11
Oman	67	67	62
Qatar	71	73	76
Other	36	38	46
TOTAL	186	191	198
NGLs (MBBL)
Dolphin	8	10	13
Other	1	—	1
TOTAL	9	10	14
Natural gas (MMCF)
Bahrain	232	173	169
Dolphin	163	199	236
Oman	57	54	48
TOTAL	452	426	453
Total Production (MBOE) (a,c)	766	733	711
(See footnotes following the Sales Volumes per Day table)

85

Sales Volumes per Day	2012	2011	2010
United States
Oil (MBBL)	255	230	219
NGLs (MBBL)	73	69	52
Natural gas (MMCF)	819	782	677
Latin America (a)
Oil (MBBL) - Colombia (b)	28	29	36
Natural gas (MMCF) - Bolivia	13	15	16
Middle East/North Africa
Oil (MBBL)
Bahrain	4	4	3
Dolphin	8	9	12
Oman	66	69	61
Qatar	71	73	76
Other	36	34	42
TOTAL	185	189	194
NGLs (MBBL)
Dolphin	8	10	12
Other	1	—	1
TOTAL	9	10	13
Natural gas (MMCF)	452	426	453
Total Sales Volumes (MBOE) (a,c)	764	731	705

(a) For all periods presented, excludes volumes from the Argentine operations sold in February 2011 and classified as discontinued operations.

(b) Includes production and sales volumes per day of 5 mbbl and 4 mbbl, respectively, for the year ended December 31, 2010, related to the noncontrolling interest in a Colombian subsidiary.

(c) Natural gas volumes have been converted to BOE based on energy content of six Mcf of gas to one barrel of oil.  Barrels of oil equivalence does not necessarily result in price equivalence  The price of natural gas on a barrel of oil equivalent basis is currently substantially lower than the corresponding price for oil and has been similarly lower over the recent past. For example, in 2012, the average prices of WTI oil and NYMEX natural gas were $94.21 per barrel and $2.81 per Mcf, respectively, resulting in an oil to gas ratio of over 30.

86

Schedule II – Valuation and Qualifying Accounts	Occidental Petroleum Corporation and Subsidiaries
In millions

			Additions
	Balance at Beginning of Period		Charged to Costs and Expenses			Charged to Other Accounts		Deductions (a)			Balance at End of Period
2012
Allowance for doubtful accounts	$	16	$	—		$	—	$	—		$	16
Environmental	$	360	$	56		$	—	$	(72	)	$	344
Litigation, tax and other reserves	198		57			—		(26		)	229
	$	558	$	113		$	—	$	(98	)	$	573	(b)
2011
Allowance for doubtful accounts	$	19	$	—		$	—	$	(3	)	$	16
Environmental	$	366	$	53		$	14	$	(73	)	$	360
Litigation, tax and other reserves	193		37			—		(32		)	198
	$	559	$	90		$	14	$	(105	)	$	558	(b)
2010
Allowance for doubtful accounts	$	30	$	(9	)	$	—	$	(2	)	$	19
Environmental	$	403	$	26		$	3	$	(66	)	$	366
Litigation, tax and other reserves	226		20			6		(59		)	193
	$	629	$	46		$	9	$	(125	)	$	559	(b)

Note:  The amounts presented represent continuing operations.

(a) Primarily represents payments.

(b) Of these amounts, $98 million, $100 million and $102 million in 2012, 2011 and 2010, respectively, are classified as current.

87

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

None.

ITEM 9A. CONTROLS AND PROCEDURES

DISCLOSURE CONTROLS AND PROCEDURES

Occidental's President and Chief Executive Officer and its Executive Vice President and Chief Financial Officer supervised and participated in Occidental's evaluation of its disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934 (Exchange Act)) as of the end of the period covered by this report. Based upon that evaluation, Occidental's President and Chief Executive Officer and Executive Vice President and Chief Financial Officer concluded that Occidental's disclosure controls and procedures were effective as of December 31, 2012.

There has been no change in Occidental's internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the fourth quarter of 2012 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 are set forth in Item 8.

ITEM 9B. OTHER INFORMATION

On February 20, 2013, Occidental provided retention payment and severance benefits to Mr. William Albrecht, Vice President and President, Americas, Oxy Oil and Gas; Mr. James Lienert, Executive Vice President — Business Support; and Mr. Edward Lowe, Vice President and President, Oxy Oil and Gas - International Production among others. The arrangement for each of these named executive officers provides for a retention payment in certain circumstances, with his continued employment, equal to twice the executive's then yearly base salary, to be paid one year after a new Chief Executive Officer commences employment. If the executive is terminated without cause prior to December 31, 2014, then, subject to providing typical waivers and releases, the executive will receive (i) separation pay at his then current salary for 24 months, (ii) his target bonus amount for the year of separation and (iii) the same medical and other benefits (other than Notice and Severance Pay) as are received by employees terminated pursuant to Occidental's Notice and Severance Pay Plan in addition to the retention payment (if not previously paid).

On February 25, 2013, Occidental extended the term of the Employment Agreement of its Corporate Executive Vice President and Corporate Secretary, Donald P. de Brier, to December 31, 2014.

The foregoing descriptions of the retention payment and severance benefit arrangement and employment agreement extension are qualified in their entirety by reference to the Form of Retention Payment and Separation Benefits Attachment and the Amendment to Employment Agreement, which are attached as Exhibits 10.6 and 10.4, respectively.

Part III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Occidental has adopted a Code of Business Conduct (Code). The Code applies to the President and Chief Executive Officer; Executive Vice President and Chief Financial Officer; Vice President, Controller and 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 at 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 - forepart," and "-Board Committees - Audit Committee," "Security Ownership – Section 16(a) Beneficial Ownership Reporting Compliance," and "General Information – Nominations for Directors for Term Expiring in 2015" in Occidental's definitive proxy statement, relating to its May 3, 2013, Annual Meeting of Stockholders (2013 Proxy Statement). The list of Occidental's executive officers and related information under "Executive Officers" set forth in Part I of this report is incorporated by reference herein.

ITEM 11. EXECUTIVE COMPENSATION

This item incorporates by reference the information appearing under the captions "Compensation Discussion and Analysis," (except "Succession Planning"), "Executive Compensation Tables" and "Director Compensation" in the 2013 Proxy Statement. Pursuant to the rules and regulations under the Exchange Act, the information under the caption "Compensation Discussion and Analysis - Compensation Committee Report" shall not be deemed to be "soliciting material," or to be "filed" with the SEC, or subject to Regulation 14A or 14C under the Exchange Act or to the liabilities of Section 18 of the Exchange Act, nor shall it be deemed incorporated by reference into any filing under the Securities Act of 1933.

88

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 – Certain Beneficial Owners and Management" in the 2013 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 "Corporate Governance – Board of Directors and its Committees – Independence", and " – Related Party Transactions" in the 2013 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 captions "Ratification of Independent Auditors – Audit and Other Fees" in the 2013 Proxy Statement.

Part IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

The agreements included as exhibits to this report are included to provide information about their terms and not to provide any other factual or disclosure information about Occidental or the other parties to the agreements. The agreements contain representations and warranties by each of the parties to the applicable agreement that were made solely for the benefit of the other agreement parties and:

• should not be treated as categorical statements of fact, but rather as a way of allocating the risk among the parties if those statements prove to be inaccurate;

• have been qualified by disclosures that were made to the other party in connection with the negotiation of the applicable agreement, which disclosures are not necessarily reflected in the agreement;

• may apply standards of materiality in a way that is different from the way investors may view materiality; and

• were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement and are subject to more recent developments.

(a) (1) and (2). Financial Statements and Financial Statement Schedule

Reference is made to Item 8 of the Table of Contents of this report, where these documents are listed.

(a) (3). Exhibits

3.(i)*	Restated Certificate of Incorporation of Occidental, dated November 12, 1999 (filed as Exhibit 3.(i) to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 1999, File No. 1-9210).
3.(i)(a)*	Certificate of Change of Location of Registered Office and of Registered Agent, dated July 6, 2001 (filed as Exhibit 3.1(i) to the Registration Statement on Form S-3 of Occidental, File No. 333-82246).
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.(i)(c)*	Certificate of Amendment of Restated Certificate of Incorporation of Occidental Petroleum Corporation, dated May 1, 2009 (filed as Exhibit 3.(i)(c) to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended June 30, 2009, File No. 1-9210).
3.(ii)*	Bylaws of Occidental, as amended through May 5, 2011 (filed as Exhibit 3.(ii) to the Current Report on Form 8-K of Occidental dated May 5, 2011 (date of earliest event reported), filed May 6, 2011, File No. 1-9210).
4.1*	Indenture, dated as of August 18, 2011, between Occidental Petroleum and The Bank of New York Mellon Trust Company, N.A. (filed as Exhibit 4.1 to the Current Report on Form 8-K of Occidental dated August 15, 2011 (date of earliest event reported), 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).
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 10.68 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(b) of Form 10-K.
10.1*	Amended and Restated Employment Agreement, dated as of October 9, 2008, between Occidental and Dr. Ray R. Irani (filed as Exhibit 10.1 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended September 30, 2008, File No. 1-9210).
10.2*	Employment Agreement, dated January 28, 2010, between Occidental and Stephen I. Chazen (filed as Exhibit 10.1 to the Current Report on Form 8-K of Occidental dated January 28, 2010, File No. 1-9210).
10.3*	Amended and Restated Employment Agreement, dated October 9, 2008, between Occidental and Donald P. de Brier (filed as Exhibit 10.3 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended September 30, 2008, File No. 1-9210).

____________________________

* Incorporated herein by reference

89

10.4	Amendment to Employment Agreement, dated February 25, 2013, between Occidental and Donald P. de Brier.
10.5*	Agreement with Chief Financial Officer (filed as Exhibit 10.7 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended June 30, 2012, File No. 1-9210).
10.6	Retention Payment and Separation Benefits Attachment.
10.7*	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).
10.8*	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).
10.9*	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).
10.10*	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).
10.11*	Form of Occidental Petroleum Corporation Modified Deferred Compensation Plan (Effective December 31, 2006, Amended and Restated Effective November 1, 2008) (filed as Exhibit 10.4 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended September 30, 2008, File No. 1-9210).
10.12*	Form of Occidental Petroleum Corporation Amendment to Senior Executive Supplemental Life Insurance Plan (Effective as of January 1, 1986, Amended and Restated Effective as of January 1, 1996) (filed as Exhibit 10.5 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended September 30, 2008, File No. 1-9210).
10.13*	Form of Occidental Petroleum Corporation Amendment to Senior Executive Survivor Benefit Plan (Effective as of January 1, 1986, Amended and Restated Effective as of January 1, 1996) (filed as Exhibit 10.6 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended September 30, 2008, File No. 1-9210).
10.14*	Form of Occidental Petroleum Corporation Supplemental Retirement Plan II (Effective as of January 1, 2005, Amended and Restated as of November 1, 2008) (filed as Exhibit 10.7 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended September 30, 2008, File No. 1-9210).
10.15*	Amendment Number 1 to the Occidental Petroleum Corporation Supplemental Retirement Plan II (Effective As Of January 1, 2005, Amended And Restated As Of November 1, 2008) (filed as Exhibit 10.16 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2009, File No. 1-9210).
10.16*	Amendment Number 2 to the Occidental Petroleum Corporation Supplemental Retirement Plan II (Effective As Of January 1, 2005, Amended And Restated As Of November 1, 2008) (filed as Exhibit 10.17 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2009, File No. 1-9210).
10.17*	Amendment Number 3 to the Occidental Petroleum Corporation Supplemental Retirement Plan II (Effective As Of January 1, 2005, Amended and Restated as of November 1, 2008) (filed as Exhibit 10.18 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2011, File No. 1-9210).
10.18*	Amendment Number 4 to the Occidental Petroleum Corporation Supplemental Retirement Plan II (Effective As Of January 1, 2005, Amended and Restated as of November 1, 2008) (filed as Exhibit 10.19 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2011, File No. 1-9210).
10.19	Amendment Number 5 to the Occidental Petroleum Corporation Supplemental Retirement Plan II (Effective as of January 1, 2005, Amended and Restated as of November 1, 2008).
10.20*	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).
10.21*	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 of Occidental for the quarterly period ended September 30, 2002, File No. 1-9210).
10.22*	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 of Occidental for the quarterly period ended September 30, 2002, File No. 1-9210).
10.23*	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).
10.24*	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).
10.25*	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).
10.26*	Occidental Petroleum Corporation 2005 Long-Term Incentive Plan, as amended through October 13, 2010 (filed as Exhibit 10.1 to the Current Report on Form 8-K of Occidental dated October 13, 2010 (date of earliest event reported), filed October 14, 2010, File No. 1-9210).
10.27*	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).
10.28*	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).
10.29*	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).
10.30*	Form of Occidental Petroleum Corporation 2005 Deferred Stock Program (Restatement Effective as of November 1, 2008) (filed as Exhibit 10.8 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended September 30, 2008, File No. 1-9210).

____________________________

* Incorporated herein by reference

90

10.31*	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).
10.32*	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).
10.33*	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).
10.34*	Executive Stock Ownership Guidelines (filed as Exhibit 10.1 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended March 31, 2005, File No. 1-9210).
10.35*	Form of Restricted Stock Award for Non-Employee Directors under Occidental Petroleum Corporation 2005 Long-Term Incentive Plan (filed as Exhibit 10.1 to the Current Report on Form 8-K of Occidental dated February 16, 2006 (date of earliest event reported), filed February 22, 2006, File No. 1-9210).
10.36*	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).
10.37*	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).
10.38*	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).
10.39*	Description of Automatic Grant of Directors’ Restricted Stock Awards Pursuant to the Terms of the Occidental Petroleum Corporation 2005 Long-Term Incentive Plan (filed as Exhibit 10.2 to the Quarterly Report on Form 10-Q of Occidental dated for the fiscal quarter ended June 30, 2010, File No. 1-9210).
10.40*	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).
10.41*	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).
10.42*	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 16, 2008 (date of earliest event reported), File No. 1-9210).
10.43*	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, 2008, File No. 1-9210).
10.44*	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, 2008, File No. 1-9210).
10.45*	Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Return on Equity Incentive Award Agreement (Cash-based, Cash-settled Award) (filed as Exhibit 10.1 to the Current Report on Form 8-K of Occidental dated July 15, 2009 (Date of Earliest Event Reported), File No. 1-9210).
10.46*	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 15, 2009 (Date of Earliest Event Reported), File No. 1-9210).
10.47*	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 10.3 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended June 30, 2009, File No. 1-9210).
10.48*	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 10.4 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended June 30, 2009, File No. 1-9210).
10.49*	Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Long-Term Incentive Award Terms and Conditions (Equity-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, 2009, File No. 1-9210).
10.50*	Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Long-Term Incentive Award Terms and Conditions (Equity-based, Cash-settled Award) (alternate – CV) (filed as Exhibit 10.6 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended June 30, 2009, File No. 1-9210).
10.51*	Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Restricted Stock Incentive Award Terms and Conditions (filed as Exhibit 10.2 to the Current Report on Form 8-K of Occidental dated October 13, 2010 (date of earliest event reported), filed October 14, 2010, File No. 1-9210).
10.52*	Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Total Shareholder Return Incentive Award Terms and Conditions (Equity-based, Equity and Cash-settled Award) (filed as Exhibit 10.3 to the Current Report on Form 8-K of Occidental dated October 13, 2010 (date of earliest event reported), filed October 14, 2010, File No. 1-9210).
10.53*	Form of Amendment to 2008 Return On Equity Incentive Award Grant Agreement (filed as Exhibit 10.1 to the Current Report on Form 8-K of Occidental dated July 13, 2011 (date of earliest event reported), filed July 18, 2011, File No. 1-9210).
10.54*	Form of Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Total Shareholder Return Incentive Award Terms and Conditions (Equity-based, Equity and Cash-settled Award) (filed as Exhibit 10.2 to the Current Report on Form 8-K of Occidental dated July 13, 2011 (date of earliest event reported), filed July 18, 2011, File No. 1-9210).

____________________________

* Incorporated herein by reference

91

10.55*	Form of Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Restricted Stock Incentive Award Terms and Conditions (filed as Exhibit 10.3 to the Current Report on Form 8-K of Occidental dated July 13, 2011 (date of earliest event reported), filed July 18, 2011, File No. 1-9210).
10.56*	Form of Acknowledgment Letter (filed as Exhibit 10.4 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended June 30, 2011, File No. 1-9210).
10.57*	Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Long-Term Incentive Award Terms and Conditions (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, 2011, File No. 1-9210).
10.58*	Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Occidental Chemical Corporation Return on Assets Incentive Award Terms and Conditions (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, 2011, File No. 1-9210).
10.59*	Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Occidental Oil and Gas Corporation Return on Assets Incentive Award Terms and Conditions (Cash-Based, Cash-Settled Award) (filed as Exhibit 10.7 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended June 30, 2011, File No. 1-9210).
10.60*	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 Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended March 31, 2012, File No. 1-9210).
10.61*	Form of Restricted Stock Unit Award for Non-Employee Directors under Occidental Petroleum Corporation 2005 Long-Term Incentive Plan (filed as Exhibit 10.2 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended March 31, 2012, File No. 1-9210).
10.62*	Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Restricted Stock Award Terms and Conditions. (filed as Exhibit 10.3 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended March 31, 2012, File No. 1-9210).
10.63*	Form of Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Total Shareholder Return Incentive Award Terms And Conditions (Equity-based and Equity-settled Award) (filed as Exhibit 10.2 to Occidental's Current Report on Form 8-K dated July 11, 2012 (date of earliest event reported), filed July 13, 2012, File No. 1-9210).
10.64*	Form of Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Restricted Stock Incentive Award Terms and Conditions (filed as Exhibit 10.3 to Occidental's Current Report on Form 8-K dated July 11, 2012 (date of earliest event reported), filed July 13, 2012, File No. 1-9210).
10.65*	Form of Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Long-Term Incentive Award Terms and Conditions (Cash-Based, Equity And Cash-Settled Award) (filed as Exhibit 10.3 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended June 30, 2012, File No. 1-9210).
10.66*	Form of Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Occidental Chemical Corporation Return on Assets Incentive Award Terms and Conditions (Cash-Based, Cash-Settled Award) (filed as Exhibit 10.4 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended June 30, 2012, File No. 1-9210).
10.67*	Form of Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Occidental Oil and Gas Corporation Return on Assets Incentive Award Terms and Conditions (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, 2012, File No. 1-9210).
10.68*	Form of Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Common Stock and Sign-On Bonus and Other Award Agreement (filed as Exhibit 10.6 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended June 30, 2012, 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, 2012.
21	List of subsidiaries of Occidental at December 31, 2012.
23.1	Consent of Independent Registered Public Accounting Firm.
23.2	Consent of Independent Petroleum Engineers.
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.
99.1	Ryder Scott Company Process Review of the Estimated Future Reserves and Income Attributable to Certain Fee, Leasehold and Royalty Interests and Certain Economic Interests Derived Through Certain Production Sharing Contracts as of December 31, 2012.
101.INS	XBRL Instance Document.
101.SCH	XBRL Taxonomy Extension Schema Document.
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document.
101.LAB	XBRL Taxonomy Extension Label Linkbase Document.
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document.
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document.

____________________________

* Incorporated herein by reference

92

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 26, 2013	By:	/s/ Stephen I. Chazen
		Stephen I. Chazen
		President
		and Chief Executive Officer

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

	Title	Date
/s/Stephen I. Chazen	President,	February 26, 2013
Stephen I. Chazen	Chief Executive Officer and Director
/s/ Cynthia L. Walker	Executive Vice President and	February 26, 2013
Cynthia L. Walker	Chief Financial Officer
/s/ Roy Pineci	Vice President, Controller and	February 26, 2013
Roy Pineci	Principal Accounting Officer
/s/ Spencer Abraham	Director	February 26, 2013
Spencer Abraham
/s/ Howard I. Atkins	Director	February 26, 2013
Howard I. Atkins
/s/ Edward P. Djerejian	Director	February 26, 2013
Edward P. Djerejian
/s/ John E. Feick	Director	February 26, 2013
John E. Feick
/s/ Margaret M. Foran	Director	February 26, 2013
Margaret M. Foran
/s/ Carlos M. Gutierrez	Director	February 26, 2013
Carlos M. Gutierrez
/s/ Ray R. Irani	Executive Chairman	February 26, 2013
Dr. Ray R. Irani	of the Board of Directors

93

	Title	Date
/s/Avedick B. Poladian	Director	February 26, 2013
Avedick B. Poladian
/s/ Aziz D. Syriani	Director	February 26, 2013
Aziz D. Syriani
/s/ Rosemary Tomich	Director	February 26, 2013
Rosemary Tomich

94

EXHIBITS FILED WITH THIS REPORT

10.4	Amendment to Employment Agreement, dated February 25, 2013, between Occidental and Donald P. de Brier.
10.6	Retention Payment and Separation Benefits Attachment.
10.19	Amendment Number 5 to the Occidental Petroleum Corporation Supplemental Retirement Plan II (Effective as of January 1, 2005, Amended and Restated as of November 1, 2008).
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, 2012.
21	List of subsidiaries of Occidental at December 31, 2012.
23.1	Consent of Independent Registered Public Accounting Firm.
23.2	Consent of Independent Petroleum Engineers.
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.
99.1	Ryder Scott Company Process Review of the Estimated Future Reserves and Income Attributable to Certain Fee, Leasehold and Royalty Interests and Certain Economic Interests Derived Through Certain Production Sharing Contracts as of December 31, 2012.
101.INS	XBRL Instance Document.
101.SCH	XBRL Taxonomy Extension Schema Document.
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document.
101.LAB	XBRL Taxonomy Extension Label Linkbase Document.
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document.
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document.

95

EX-10.4

EXHIBIT 10.4

AMENDMENT

TO

EMPLOYMENT AGREEMENT

This Amendment to Employment Agreement (this “Amendment”) is made as of the 25^th day of February, 2013 by and between Occidental Petroleum Corporation, a Delaware corporation (hereinafter referred to as “Employer”), and Donald P. de Brier (hereinafter referred to as “Employee”).

WITNESSETH

WHEREAS, Employee has been rendering services to Employer, most recently pursuant to a written agreement between Employee and Employer dated October 9, 2008 (the “Agreement”); and

WHEREAS, the parties now desire to amend the Agreement in certain respects;

NOW, THEREFORE, in consideration of the mutual covenants and agreements herein, Employer and Employee hereby agree to amend the Agreement as follows:

1.Employer and Employee acknowledge that Employee's position now is Corporate Executive Vice President and Corporate Secretary.

2.In accordance with the Paragraphs 2 and 9 of the Agreement, the term of employment under the Agreement is extended to midnight December 31, 2014, unless terminated prior thereto in accordance with the provisions of the Agreement, or unless extended by mutual agreement in accordance with Paragraphs 2 and 9 of the Agreement.

3.As amended by this Amendment, the Agreement shall continue in full force and effect for the extended term described in the preceding paragraph. The provisions of Paragraphs 9 through 14 of the Agreement shall apply to this Amendment, but with all references to the Agreement being deemed to refer to this Amendment.

IN WITNESS WHEREOF, the parties hereto have executed this Amendment the day and year first above written.

/s/ DONALD P. DE BRIER
Donald P. de Brier
OCCIDENTAL PETROLEUM CORPORATION
By:	/s/ MARTIN A. COZYN
	Martin A. Cozyn, Executive Vice President - Human Resources

EX-10.6

EXHIBIT 10.6

RETENTION PAYMENT AND SEPARATION BENEFITS

ATTACHMENT

a. Retention Payment. Oxy will pay you an amount equal to 2 times your then yearly base salary in one lump sum cash payment at the date that is one year after the new CEO commences employment.

b. Separation Benefits. If, prior to December 31, 2014, Oxy terminates you without cause, then, subject to your timely execution of waivers and releases of the type required by Oxy's Notice and Severance Pay Plan, you will receive in addition to your Retention Payment, at your separation date or the time otherwise provided below:

1. Separation pay at your then current base salary for 24 months;

2. Your target annual bonus amount for the year of separation; and

3. The same medical and other benefits (other than Notice and Severance Pay) as are received by employees terminated pursuant to Oxy's Notice and Severance Pay Plan.

Payments of your separation pay under Paragraph b.1 shall be made monthly beginning the month after separation; provided, however, that to the extent required by Section 409A of the U.S. Internal Revenue Code and the regulations promulgated thereunder (“Section 409A”), the payment of certain amounts will be delayed until the seventh month that begins after your separation date. Payment under Paragraph b.2 will be made as soon as practicable after the date you become entitled to the payment under this provision or at the time provided for in any underlying compensation arrangement or plan if required for compliance with Section 409A. Although not guaranteed by the Company, payments under this attachment are intended to be exempt or compliant with Section 409A, and the attachment will be interpreted accordingly. Payments under this attachment will be subject to all applicable tax and tax-related items withholding requirements. In addition, the separation payments to be paid pursuant to this attachment will not exceed the amount permitted under Oxy's Golden Parachute Policy unless such separation payments are approved by a vote of Oxy's stockholders.

c. Other Benefits. The foregoing is not intended to be a comprehensive listing of the benefits to which you may be entitled at the time of your separation, including your rights under any outstanding incentive awards. In addition, the Executive Compensation and Human Resources Committee may, in its sole discretion, decide to provide additional separationbenefits.

Ret&SepBen - NEO

EX-10.19

EXHIBIT 10.19

AMENDMENT NUMBER 5

TO THE

OCCIDENTAL PETROLEUM CORPORATION

SUPPLEMENTAL RETIREMENT PLAN II

Effective as of January 1, 2005

Amended and Restated as of November 1, 2008

The Occidental Petroleum Corporation Supplemental Retirement Plan II (Effective as of January 1, 2005, Amended and Restated as of November 1, 2008) (the “Plan”) is hereby amended as of January 1, 2013, as follows:

1.The following new definition of “Secondary Threshold Amount” is added as subsection 2.1(x) and all subsequent subsections under section 2.1 and any cross-references in the Plan to such subsections are renumbered accordingly:

(x) “Secondary 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 plus Annual Bonus awarded in the Plan Year, less any portion of such Annual Bonus deferred under the Deferred Compensation Plan, each determined as of May 1 of the Plan Year, at which the sum of all contributions made by and on behalf of an Employee under the Savings Plan and Retirement Plan would exceed the dollar limit in effect for the Plan Year under Code section 415(c)(1)(A), based on (1) the maximum contribution rates for the most highly compensated employees and maximum employer matching contribution rates under the Savings Plan and (2) the employer contribution rates for Employees who have attained age 35 as of the last day of the Plan Year under the Retirement Plan.

2.The definition of “Threshold Amount” in subsection 2.1(bb) (as renumbered pursuant to the prior amendment) is amended to read as follows:

(bb) “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 all contributions made by and on behalf of an Employee under the Savings Plan and Retirement Plan would exceed the dollar limit in effect for the Plan Year under Code section 415(c)(1)(A), based on (1) an assumed level of Annual Bonus for a particular level of Base Pay of Record determined by the Company in advance of the Plan Year, (2) the maximum contribution rates for the most highly compensated employees and maximum employer matching contribution rates under the Savings Plan, and (3) the employer contribution rate for Employees who have attained age 35 as of the last day of the Plan Year under the Retirement Plan.

3.Subsection (a) in section 3.1 is amended to read as follows:

(a) The first day on which the Employee's annualized Base Pay of Record exceeds the Threshold Amount or, with respect to an Employee whose annualized Base Pay of Record does not exceed the Threshold Amount, May 1st of a Plan Year if the sum of the Employee's annualized Base Pay of Record as of May 1 of the Plan Year and Annual Bonus awarded during the Plan Year, less any portion of such Annual Bonus deferred under the Deferred Compensation Plan, exceeds the Secondary Threshold Amount.

4.The following new paragraph (2) is added to section 4.1(a) of the Plan and current paragraph (2) is renumbered as paragraph (3).

(2)An Employee:

(A) Who is eligible to participate in the Savings Plan and the Retirement Plan for the Plan Year, and

(B) The sum of whose annualized Base Pay of Record as of May 1 of the Plan Year and Annual Bonus awarded during the Plan Year, less any portion of such Annual Bonus deferred under the Deferred Compensation Plan, exceeds the Secondary Threshold Amount applicable to the Employee for the Plan Year.

Whether an Employee meets the requirements of this paragraph (2) shall be determined as of May 1^st of each Plan Year by the Company. An Employee who meets such requirements shall be eligible for the allocation specified in subsection (b) beginning as of May 1^st of the Plan Year (or with respect to a newly eligible Employee, once the Employee's participation in the Plan has commenced pursuant to Section 3.1). Until such determination is made during the Plan Year (and, with respect to a newly eligible Employee, the Employee's participation in the Plan has commenced pursuant to Section 3.1), an Employee shall not be treated as actively participating in this Plan with respect to a Plan Year by reason of this paragraph (2) and, unless otherwise eligible under paragraph (1), shall not be entitled to the allocations specified in subsection (b) for the Plan Year.

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

EX-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,	2012			2011				2010			2009			2008
Income from continuing operations	$	4,635	(a)	$	6,640			$	4,641		$	3,202		$	7,299
Subtract:
Net income attributable to noncontrolling interest	—			—				(72		)	(51		)	(116		)
Adjusted income from equity investments (b)	163			(33		)		(60		)	(88		)	(84		)
	4,798			6,607				4,509			3,063			7,099
Add:
Provision for taxes on income (other than foreign oil and gas taxes)	708			1,795				1,099			695			2,213
Interest and debt expense	130			135			(c)	116			140			133
Portion of lease rentals representative of the interest factor	59			60				57			57			58
	897			1,990				1,272			892			2,404
Earnings before fixed charges	$	5,695		$	8,597			$	5,781		$	3,955		$	9,503
Fixed charges:
Interest and debt expense including capitalized interest	$	254		$	221		(c)	$	203		$	218		$	201
Portion of lease rentals representative of the interest factor	59			60				57			57			58
Total fixed charges	$	313		$	281			$	260		$	275		$	259
Ratio of earnings to fixed charges	18.19			30.59				22.23			14.38			36.69

Note:  Argentine operations have been reflected as discontinued operations for all periods.

(a)	Includes after-tax charges of $1.1 billion for the impairment of domestic gas assets and related items.
(b)	Represent adjustments to arrive at distributed income of equity investees.
(c)	Excludes a pre-tax charge of $163 million for the early redemption of debt.

EX-21

EXHIBIT 21

LIST OF SUBSIDIARIES

The following is a list of the Registrant’s subsidiaries at December 31, 2012, other than certain inactive subsidiaries that did not in the aggregate constitute a significant subsidiary.

Name	Jurisdiction of Formation
Armand Products Company		Delaware
Bravo Pipeline Company		Delaware
BridgeTex Pipeline Company, LLC		Delaware
Carbocloro S.A. Industrias Quimicas		Brazil
Centurion Pipeline GP, Inc.		Delaware
Centurion Pipeline L.P.		Delaware
Centurion Pipeline LP, Inc.		Delaware
D.S. Ventures, Inc.		Texas
DMM Financial LLC		Delaware
EHPP Holdings Inc.		Delaware
Elk Hills Power, LLC		Delaware
Glenn Springs Holdings, Inc.		Delaware
ICC Resin Technology, Inc.		Delaware
INDSPEC Chemical Corporation		Delaware
INDSPEC Holding Corporation		Delaware
Ingleside Cogeneration GP 2, Inc.		Delaware
Ingleside Cogeneration GP, Inc.		Delaware
Ingleside Cogeneration Limited Partnership		Delaware
Joslyn Partnership		Alberta, Canada
Laguna Petroleum Corporation		Texas
Lomita Gasoline Company, Inc.		California
Marico Exploration, Inc.		New Mexico
MC2 Technologies Inc.		Delaware
Miller Springs Remediation Management, Inc.		Delaware
Moncrief Minerals Partnership, L.P.		Texas
Monument Production, Inc.		California
MTD Pipeline LLC		Delaware
Natural Gas Odorizing, Inc.		Oklahoma
NGL Ventures LLC		Delaware
Occidental Al Hosn, LLC		Delaware
Occidental (Bermuda) Ltd.		Bermuda
Occidental (East Shabwa), LLC		Nevis
Occidental Andina, LLC		Delaware
Occidental Canada Holdings Ltd.		Nova Scotia
Occidental Chemical Chile Limitada		Chile
Occidental Chemical Corporation		New York
Occidental Chemical de Mexico, S.A. de C.V.		Mexico
Occidental Chemical Holding Corporation		California
Occidental Chemical International, Inc.		California
Occidental Chemical Nevis, Inc.		Nevis
Occidental Chile Investments, LLC		Delaware
Occidental Chile Minority Holder, LLC		Delaware

EXHIBIT 21 (cont'd)

Name	Jurisdiction of Formation
Occidental Colombia (Series G) Ltd.		Bermuda
Occidental Colombia (Series J) Ltd.		Bermuda
Occidental Crude Sales, Inc. (International)		Delaware
Occidental Crude Sales, LLC (South America)		Delaware
Occidental de Colombia, LLC		Delaware
Occidental del Ecuador, Inc.		Nevis
Occidental Dolphin Holdings Ltd.		Bermuda
Occidental Energy Marketing, Inc.		Delaware
Occidental Energy Transportation LLC		Delaware
Occidental Energy Ventures Corp.		Delaware
Occidental Exploration and Production Company		California
Occidental International (Libya), Inc.		Delaware
Occidental International Exploration and Production Company		California
Occidental International Holdings Ltd.		Bermuda
Occidental International Oil and Gas Ltd.		Bermuda
Occidental International Services, Inc.		Delaware
Occidental Joslyn GP 1 Co.		Nova Scotia
Occidental Joslyn GP 2 Co.		Nova Scotia
Occidental Karawan Holding Ltd.		Bermuda
Occidental Karawan, LLC		Delaware
Occidental Latin America Holdings, Inc.		Delaware
Occidental Libya Oil & Gas B.V.		The Netherlands
Occidental Middle East Development Company		Delaware
Occidental Midstream Projects Ltd.		Bermuda
Occidental Mukhaizna, LLC		Delaware
Occidental of Abu Dhabi (Bab) Ltd.		Bermuda
Occidental of Abu Dhabi Ltd.		Bermuda
Occidental of Abu Dhabi, LLC		Delaware
Occidental of Abu Dhabi (Shah) Ltd.		Bermuda
Occidental of Bahrain (Block 1) Ltd.		Bermuda
Occidental of Bahrain (Block 3) Ltd.		Bermuda
Occidental of Bahrain (Block 4) Ltd.		Bermuda
Occidental of Bahrain (JOC Holding) LLC		Delaware
Occidental of Bahrain (Offshore), LLC		Delaware
Occidental of Bahrain Deep Gas, LLC		Delaware
Occidental of Bahrain Ltd.		Bermuda
Occidental of Bahrain Onshore Deep Gas, Ltd.		Bermuda
Occidental of Dubai, Inc.		Nevis
Occidental of Elk Hills, Inc.		Delaware
Occidental of Iraq Holdings Ltd.		Bermuda
Occidental of Iraq, LLC		Delaware
Occidental of Oman, Inc.		Nevis
Occidental of Yemen (Block 75), LLC		Delaware
Occidental of Yemen (Block S-1), Inc.		Cayman Islands
Occidental of Yemen Holdings (Block 75) Ltd.		Bermuda
Occidental Oil and Gas Corporation		Texas
Occidental Oil and Gas Holding Corporation		California
Occidental Oil and Gas International, LLC		Delaware

EXHIBIT 21 (cont'd)

Name	Jurisdiction of Formation
Occidental Oil and Gas (Oman) Ltd.		Nevis
Occidental Oil Asia Pte. Ltd.		Singapore
Occidental Oman Gas Company LLC		Delaware
Occidental Oman Gas Holdings Ltd.		Bermuda
Occidental OOOI Holder, Inc.		Delaware
Occidental Overseas Holdings BV		The Netherlands
Occidental Overseas Operations, Inc.		Delaware
Occidental Peninsula II, Inc.		Nevis
Occidental Peninsula, LLC		Delaware
Occidental Permian Ltd.		Texas
Occidental Permian Manager LLC		Delaware
Occidental Permian Services, Inc.		Delaware
Occidental Petroleum Investment Co.		California
Occidental Petroleum of Oman Ltd.		Nevis
Occidental Petroleum of Qatar Ltd.		Bermuda
Occidental Power Marketing, L.P.		Delaware
Occidental Power Services, Inc.		Delaware
Occidental PVC, LLC		Delaware
Occidental Qatar Energy Company LLC		Delaware
Occidental Quimica do Brasil Ltda.		Brazil
Occidental Resources Company		Cayman Islands
Occidental Shah Gas Holdings Ltd.		Bermuda
Occidental Tower Corporation		Delaware
Occidental Transportation Holding Corporation		Delaware
Occidental Yemen Ltd.		Bermuda
Occidental Yemen Sabatain, Inc.		Nevis
OEVC Energy, LLC		Texas
OEVC Midstream Projects, LLC		Delaware
OOG Partner LLC		Delaware
OOOI Chem Holdings, LLC		Delaware
OOOI Chem Sub, LLC		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
Opcal Insurance, Inc.		Hawaii
OPM GP, Inc.		Delaware
Oxy BridgeTex Limited Partnership		Texas
Oxy BT Holdings GP, Inc.		Texas
Oxy BT Holdings LP, Inc.		Texas
Oxy Cogeneration Holding Company, Inc.		Delaware
Oxy Colombia Holdings, Inc.		Delaware
OXY CV Pipeline LLC		Delaware
Oxy Dolphin E&P, LLC		Nevis
Oxy Dolphin Pipeline, LLC		Nevis
Oxy Energy Canada, Inc.		Delaware
Oxy Energy Services, Inc.		Delaware

EXHIBIT 21 (cont'd)

Name	Jurisdiction of Formation
Oxy Expatriate Services, Inc.		Delaware
Oxy Holding Company (Pipeline), Inc.		Delaware
OXY Inc.		California
Oxy Ingleside Energy Center, LLC		Delaware
OXY Libya E&P Concession 103 Ltd.		Bermuda
OXY Libya E&P EPSA 102 B.V.		The Netherlands
OXY Libya E&P EPSA 1981 Ltd.		Bermuda
OXY Libya E&P EPSA 1985 Ltd.		Bermuda
OXY Libya E&P NC 143, 144, 145, 150 B.V.		The Netherlands
OXY Libya, LLC		Delaware
OXY LNG, Inc.		Delaware
OXY Little Knife, LLC		Delaware
OXY Long Beach, Inc.		Delaware
OXY Lost Hills, Inc.		Delaware
OXY LPG LLC		Delaware
Oxy LPG Terminal, LLC		Delaware
Oxy Midstream Strategic Development LLC		Delaware
OXY NM LP		Texas
OXY Oil Partners, Inc.		Delaware
Oxy Oleoducto SOP, LLC		Delaware
Oxy Overseas Services Ltd.		Bermuda
OXY PBLP Holder, Inc.		Delaware
OXY PBLP Manager, LLC		Delaware
Oxy Pipeline I Company		Delaware
OXY Support Services, LLC		Delaware
OXY Tidelands, Inc.		Delaware
Oxy Transport I Company		Delaware
OXY USA Inc.		Delaware
OXY USA WTP LP		Delaware
Oxy Vinyls Canada Co.		Nova Scotia
Oxy Vinyls, LP		Delaware
OXY VPP Investments, Inc.		Delaware
OXY West, LLC		Texas
Oxy Westwood Corporation		California
OXY Wilmington, LLC		Delaware
Oxy Y-1 Company		New Mexico
OxyChile Investments, LLC		Delaware
Oxycol Holder Ltd.		Bermuda
OXYMAR		Texas
Permian Basin Limited Partnership		Delaware
Permian VPP Holder, LP		Delaware
Permian VPP Manager, LLC		Delaware
Phibro (Asia) Pte. Ltd.		Singapore
Phibro Commodities Limited		United Kingdom
Phibro GmbH		Switzerland
Phibro LLC		Delaware
Phibro Limited		United Kingdom
Phibro Service LLC		Delaware

EXHIBIT 21 (cont'd)

Name	Jurisdiction of Formation
Phibro Trading LLC		Delaware
Placid Oil Company		Delaware
Rio de Viento, Inc.		Wyoming
San Patricio Pipeline LLC		Delaware
Scanports Ltd.		United Kingdom
Scanports Shipping, Inc.		Delaware
Shipalks Shipping Ltd.		United Kingdom
Southern San Joaquin Production, LLC		Delaware
Swiflite Aircraft Corporation		New Jersey
Tenby, Inc.		California
Thums Long Beach Company		Delaware
Tidelands Oil Production Company		Texas
Turavent Oil AG		Switzerland
Vintage Gas, Inc.		Oklahoma
Vintage Petroleum Boliviana, Ltd.		Bermuda
Vintage Petroleum International Finance B.V.		Netherlands
Vintage Petroleum International Holdings, Inc.		Delaware
Vintage Petroleum International Ventures, Inc.		Cayman Islands
Vintage Petroleum International, Inc.		Oklahoma
Vintage Petroleum South America Holdings, Inc.		Cayman Islands
Vintage Petroleum South America, LLC		Oklahoma
Vintage Petroleum, LLC		Delaware
Vintage Production California LLC		Delaware

EX-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. 33-64719, 333-55404, 333-63444, 333-78031, 333-83124, 333-96951, 333-104827, 333-124732, 333-142705and 333-176308) on Forms S-3 and S-8 of Occidental Petroleum Corporation of our reports dated February 26, 2013, with respect to the consolidated balance sheets of Occidental Petroleum Corporation as of December 31, 2012 and 2011, and the related consolidated statements of income, comprehensive income, stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2012 and the related financial statement schedule, and the effectiveness of internal control over financial reporting as of December 31, 2012, which reports appear in the December 31, 2012 annual report on Form 10-K of Occidental Petroleum Corporation.

/s/ KPMG LLP

Los Angeles, California

February 26, 2013

EX-23.2

EXHIBIT 23.2

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

To the Board of Directors

Occidental Petroleum Corporation:

We consent to the (i) inclusion in the Occidental Petroleum Corporation (Occidental) Form 10-K for the year ended December 31, 2012, and the incorporation by reference in Occidental's registration statements (Nos. 33-64719, 333-55404, 333-63444, 333-78031, 333-83124, 333-96951, 333-104827, 333-124732, 333-142705 and 333-176308) (the “Registration Statements”), of references to our name and to our letter dated February 5, 2013, relating to our review of the methods and procedures used by Occidental for estimating its oil and gas proved reserves (our “Letter”), (ii) filing of our Letter with the Securities and Exchange Commission as Exhibit 99.1 to the Form 10-K and (iii) incorporation by reference of our Letter in the Registration Statements.

/s/ RYDER SCOTT COMPANY, L.P.

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

Houston, Texas

February 26, 2013

EX-31.1

EXHIBIT 31.1

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;

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 26, 2013

/s/ STEPHEN I. CHAZEN

Stephen I. Chazen

President and Chief Executive Officer

EX-31.2

EXHIBIT 31.2

RULE 13a – 14(a) / 15d – 14(a)

CERTIFICATION

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

I, Cynthia L. Walker, 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 26, 2013

/s/ CYNTHIA L. WALKER

Cynthia L. Walker

Executive Vice President and

Chief Financial Officer

EX-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, 2012, as filed with the Securities and Exchange Commission on February 26, 2013 (the “Report”), Stephen I. Chazen, as Chief Executive Officer of the Company, and Cynthia L. Walker, 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 or her knowledge, respectively:

(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/ STEPHEN I. CHAZEN
Name:	Stephen I. Chazen
Title:	President and Chief Executive Officer
Date:	February 26, 2013

/s/ CYNTHIA L. WALKER
Name:	Cynthia L. Walker
Title:	Executive Vice President and Chief Financial Officer
Date:	February 26, 2013

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.

EX-99.1

EXHIBIT 99.1

OCCIDENTAL PETROLEUM CORPORATION

Process Review

of the

Estimated

Future Reserves and Income

Attributable to Certain

Fee, Leasehold and Royalty Interests

and

Certain Economic Interests

Derived Through Certain Production Sharing Contracts

SEC Parameters

As of

December 31, 2012

\s\ Jennifer Fitzgerald

Jennifer A. Fitzgerald, P.E.

TBPE License No. 100572

Vice President

[SEAL]

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

TBPE REGISTERED ENGINEERING FIRM F-1580    FAX (713) 651-0849

1100 LOUISIANA SUITE 4600    HOUSTON, TEXAS 77002-5294    TELEPHONE (713) 651-9191

February 5, 2013

Occidental Petroleum Corporation

10889 Wilshire Boulevard, 16^th Floor

Los Angles, California 90024

Ladies and Gentlemen:

At your request, Ryder Scott Company, L.P. (Ryder Scott) has conducted a process review of the methods and analytical procedures utilized by the engineering and geological staff of Occidental Petroleum Corporation (Occidental) for estimating the proved reserves volumes, preparing the economic evaluations and determining the reserves classifications as of December 31, 2012, based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). The results of our third party reserves process review, completed on January 10, 2013 and presented herein, were prepared for public disclosure by Occidental in filings made with the SEC in accordance with the disclosure requirements set forth under Section 229.1202(a)(8) of the SEC regulations.

Based on our review, including the data, technical processes and interpretations presented by Occidental, it is our opinion that the overall procedures and methodologies utilized by Occidental in estimating the proved reserves volumes, documenting the changes in reserves from prior estimates, preparing the economic evaluations and determining the reserves classifications for the reviewed properties are appropriate for the purpose thereof, and comply with the SEC regulations as of December 31, 2012. Ryder Scott has not been engaged to render an opinion as to the reasonableness of reserves quantities reported by Occidental.

Properties Reviewed

The proved reserves reviewed herein are attributable to the fee, leasehold and royalty interests of Occidental in certain properties located in the United States in the states of California, Colorado, Kansas, and Texas and derived through Occidental’s economic interest as defined in certain production sharing contracts for certain properties located in the Middle East.

The properties reviewed herein were selected by Occidental. Ryder Scott and Occidental concur that these properties are a valid representation of Occidental’s total net proved reserves portfolio as of December 31, 2012. Based on the estimates prepared by Occidental, the portion of total company net liquid and net gas reserves reviewed by us are expressed as a percentage and presented in summary form on the following page. At Occidental’s request, we have also presented the portion of the total company net reserves reviewed by us on a barrel of oil equivalent (BOE) basis.

SUITE 600, 1015 4TH STREET, S.W.    CALGARY, ALBERTA T2R 1J4    TEL (403) 262-2799    FAX (403) 262-2790

621 17TH STREET, SUITE 1550    DENVER, COLORADO 80293-1501    TEL (303) 623-9147    FAX (303) 623-4258

Occidental Petroleum Corporation

February 5, 2013

Page 2

Percentage of Total Company Estimated Net Reserves

Reviewed by Ryder Scott

SEC Parameters

Occidental Petroleum Corporation

As of December 31, 2012

	Oil/Condensate	NGL	Total Liquid Hydrocarbons	Gas	Equivalent MMBOE
Total Proved Developed	12%	50%	17%	41%	24%
Total Proved Undeveloped	7%	15%	8%	12%	9%
Total Company Proved	11%	38%	15%	33%	20%

The net liquid hydrocarbons reviewed are comprised of oil, condensate and natural gas liquids (NGL) and are based on standard 42 gallon barrels. All net gas volumes reviewed are based on an “as sold” basis expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located.Reserves reviewed and noted herein on an equivalent barrel (BOE) basis are based on converting natural gas on the basis of relative energy content using a factor of 6,000 cubic feet of natural gas per one barrel of oil equivalent. It should be noted that barrel of oil equivalence does not necessarily result in price equivalence as the equivalent price of natural gas on a barrel of oil equivalent basis is, and has been substantially lower than the corresponding price for crude oil currently and over the recent past.

Reserves Process Review Discussion

A process review, according to Paragraph 2.2(h) contained in the Society of Petroleum Engineers (SPE) Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (SPE auditing standards), is “the result of an investigation to address the adequacy and effectiveness of an entity’s internal processes and controls relative to reserves estimation.”

In order to arrive at our conclusions and to substantiate our opinion relative to Occidental’s internal reserves estimation process and controls, we conducted our investigation in a manner that closely conforms to the SPE auditing standards for a reserves audit. Under Paragraph 2.2(f) of the SPE auditing standards, a reserves audit includes “the process of reviewing certain of the pertinent facts interpreted and assumptions made that have resulted in an estimate of reserves and/or Reserves Information prepared by others and the rendering of an opinion about (1) the appropriateness of the methodologies employed, (2) the adequacy and quality of the data relied upon, (3) the depth and thoroughness of the reserves estimation process, and (4) the classification of reserves appropriate to the relevant definitions used.”

Our process review, however, differs from an SPE reserves audit in that we have not conducted our investigation with sufficient rigor to express an opinion as to “the reasonableness of the estimated reserve quantities and/or the Reserves Information” as required under item (5) Paragraph 2.2(f) of the SPE auditing standards for a reserves audit. Our review should not be construed to be a complete and comprehensive appraisal of the subject properties or deemed to convey the same level of information contained in a third party reserves audit or reserves evaluation report.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Occidental Petroleum Corporation

February 5, 2013

Page 3

Applicable Petroleum Reserves Definitions

The determination of the proved reserves classifications as discussed herein are based on the definitions as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a) released January 14, 2009 in the Federal Register, Volume 74, pages 2158 through 2197.

Reserves and Uncertainty

The SEC defines reserves as the “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserve estimates involve an assessment of the uncertainty relating to the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty as to their recoverability.

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserves quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserves category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty that the estimates of the quantities actually recovered are “much more likely to be achieved than not.” The SEC defines probable reserves as “those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC defines possible reserves as “those additional reserves that are less certain to be recovered than probable reserves.” All quantities of reserves within the same reserves category must meet the SEC definitions as noted above.

The reserves for the properties reviewed by us were estimated by Occidental using deterministic methods and presented as incremental quantities. Under the deterministic incremental approach, discrete quantities of reserves are estimated and assigned separately as proved, probable or possible based on their individual level of uncertainty. At Occidental’s request, this reserves process review addresses only the proved reserves attributable to the properties reviewed herein.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved, probable and possible reserves quantities and their associated reserves categories may be revised due to other factors such as the results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Occidental Petroleum Corporation

February 5, 2013

Page 4

Reserves Process Review Procedure

Certain technical personnel responsible for the preparation of Occidental’s proved reserves estimates presented the data, methods and procedures used in 1) estimating the reserves volumes as of December 31, 2012; 2) documenting the changes in reserves from prior estimates; 3) preparing the economic evaluations associated with the estimated December 31, 2012 reserves; and 4) determining the reserves classifications for each of the subject properties reviewed. We consulted with these technical personnel and had access to their workpapers and supporting data in the course of our review. Furthermore, if in the course of our examination something came to our attention which brought into question the appropriateness of the methodologies employed, the adequacy of the data relied upon or the documentation of the reserves estimation process, additional clarification was requested from Occidental until we had satisfactorily resolved our questions relating thereto.

Methodology and Procedure Employed by Occidental for Estimating Reserves

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy. These methods may be used singularly or in combination by the reserves evaluator in the process of estimating the quantities of reserves. Reserves evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property.

The proved reserves for the properties that we reviewed were estimated by performance methods, analogy, reservoir modeling or a combination of methods. Approximately 43 percent of the proved reserves attributable to producing wells or reservoirs for the properties reviewed were estimated by performance methods using decline curve analysis and/or material balance which utilized extrapolations of historical production and pressure data in those cases where such data were considered to be definitive. The remaining 57 percent of the proved reserves attributable to the producing wells for the properties reviewed were estimated by a combination of methods including type curves supported by analogs and reservoir modeling to 1) estimate those reserves where there were inadequate historical performance data to establish a definitive producing trend and 2) estimate the incremental reserves attributable to enhanced/improved oil recovery. The data used by Occidental in their analysis of the proved reserves for the producing properties reviewed by us was considered sufficient for the purpose thereof.

Approximately 15 percent of the proved developed non-producing reserves were estimated by performance methods using analogy to prior established decline trends. The remaining 85 percent of the proved developed non-producing reserves and all of the proved undeveloped reserves were estimated by a combination of methods including type curves supported by analogs and reservoir modeling as noted above. The data used by Occidental in their analysis of the non-producing and undeveloped reserves for the properties reviewed by us was considered sufficient for the purpose thereof.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Occidental Petroleum Corporation

February 5, 2013

Page 5

Of the properties reviewed, approximately 26 percent of the proved producing reserves and 38 percent of the proved non-producing and undeveloped reserve volumes are related to the application of enhanced/improved recovery techniques. These enhanced/improved recovery techniques include water and CO₂ injection and infill drilling.

Occidental uses the latest available production, new well and seismic data in its reserves estimation process. Typically, this data is from the third quarter of the year for which reserves are estimated, though material data is considered whenever it becomes available prior to finalization of reserves estimates. The data used by Occidental in their analysis of the proved reserves for the properties reviewed by us was considered sufficient for the purpose thereof.

Primary Economic Assumptions Employed by Occidental for Estimating Reserves

To estimate economically recoverable proved reserves and related future net cash flows, Occidental considered many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. To confirm that the proved reserves reviewed by us meet the SEC requirements to be economically producible, we have reviewed certain primary economic data utilized by Occidental relating to hydrocarbon prices and costs as noted herein.

The hydrocarbon prices in effect on December 31, 2012 for the properties reviewed were determined by Occidental using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold and adjustments for differentials as described herein. In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices including fixed and determinable escalations, exclusive of inflation adjustments, were used until expiration of the contract.

The table below summarizes Occidental’s net volume weighted benchmark prices adjusted for differentials for the properties reviewed by us and referred to herein as Occidental’s “average realized prices.” The average realized prices shown in the table below were determined from Occidental’s estimate of the total future gross revenue before production taxes for the properties reviewed by us and Occidental’s estimate of the total net reserves for the properties reviewed by us for the geographic area. A summary of average realized prices are not included for certain properties located in the Middle East because of the host government’s limitations on the disclosure of commercially sensitive information. The data shown in the table below is presented in accordance with SEC disclosure requirements for each of the geographic areas reviewed by us.

Geographic Area	Product	Price Reference	Average Benchmark Prices	Average Realized Prices
North America
United States	Oil/Condensate	WTI Cushing	$94.71/Bbl	$93.76/Bbl
	NGLs	WTI Cushing	$94.71/Bbl	$35.33/Bbl
	Gas	Henry Hub	$2.79/MMBTU	$2.95/MCF

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Occidental Petroleum Corporation

February 5, 2013

Page 6

As indicated above, the product prices that were used by Occidental to determine the future gross revenue for each property reviewed by us reflect adjustments to the benchmark prices for gravity, quality, local conditions, gathering and transportation fees and distance from market, referred to herein as “differentials.” The differentials used by Occidentalwere accepted as factual data. We have not conducted an independent verification of the data used by Occidental.

While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may also increase or decrease from existing levels, such changes were, in accordance with rules adopted by the SEC, omitted from consideration by Occidental in this process and omitted by us in conducting this review.

Accumulated gas production imbalances, if any, were not taken into account in the proved reserve estimates of gas reviewed. The proved gas volumes included herein attribute gas consumed in operations as reserves for those fields where the inclusion of such volumes was appropriate.

Operating costs used by Occidental are based on the operating expense reports of Occidental and include only those costs directly applicable to the leases or wells for the properties reviewed by us. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. For operated properties, the operating costs include an appropriate level of corporate general administrative and overhead costs. The operating costs for non-operated properties include the Council of Petroleum Accounting Societies overhead costs that are allocated directly to the leases and wells under terms of operating agreements. The operating costs used by Occidental were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Occidental.

Development costs used by Occidental are based on authorizations for expenditure (AFE) for the proposed work or actual costs for similar projects. The development costs used by Occidental were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Occidental.

The proved developed non-producing and undeveloped reserves for the properties reviewed by us were incorporated by Occidental in accordance with Occidental’s plans to develop these reserves as of December 31,2012. The implementation of Occidental’s development plans as presented to us is subject to the approval process adopted by Occidental’s management. As a result of our inquiries during the course of our review, Occidental has informed us that the development activities for the properties reviewed by us have been subjected to and received the internal approvals required by Occidental’s management at the appropriate local, regional and corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to partner AFE processes, Joint Operating Agreement requirements or other administrative approvals external to Occidental. Additionally, Occidental has informed us that they are not aware of any legal, regulatory, political or economic obstacles that would significantly alter their plans.

Future Production Rate Assumptions Employed by Occidental for Estimating Reserves

Occidental’s forecasts of future production rates are based on historical performance from wells currently on production. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Occidental Petroleum Corporation

February 5, 2013

Page 7

Test data and other related information were used by Occidental to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date determined by Occidental. Wells or locations that are not currently producing may start producing earlier or later than anticipated in Occidental’s estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing or recompleting wells and constraints set by regulatory bodies.

The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated by Occidental because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity or other operating conditions, market demand and allowables or other constraints set by regulatory bodies.

Reserves Derived by Occidental Through Certain Production Sharing Contracts

The reserves for certain properties located in the Middle East reviewed herein are limited to the period prior to expiration of current contracts providing the legal right to produce or an economic interest in such production. Furthermore, properties in different countries may be subjected to significantly varying contractual fiscal terms that affect the net revenue to Occidental for the production of these volumes. The prices and economic return received for these net volumes can vary significantly based on the terms of these contracts. Therefore, when applicable, Ryder Scott reviewed the fiscal terms of such contracts and discussed with Occidental the net economic benefit attributed to such operations for the determination of the net hydrocarbon volumes and income thereof. Occidental’s net hydrocarbon volumes for the fields reviewed in the Middle East include certain amounts corresponding to in-country income taxes where the terms of the production sharing contract include provisions for an in-kind settlement process, where production is immediately taken and sold to pay the local income tax for and on behalf of the contractor (in this case Occidental). Ryder Scott has not conducted an exhaustive audit or verification of such contractual information. Neither our review of such contractual information nor our acceptance of Occidental’s representations regarding such contractual information should be construed as a legal opinion on this matter.

Possible Effects of Regulation on Occidental’s Estimate of Reserves

Ryder Scott did not evaluate the country and geopolitical risks in the countries where Occidental operates or has interests. Occidental’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons including the granting, extension or termination of production sharing contracts, the fiscal terms of various production sharing contracts, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the quantities estimated by Occidental as reviewed herein.

We have not made any field examination of the properties. No consideration was given in this review to potential environmental liabilities that may exist nor to any costs for the potential liabilities to restore and clean up damages, if any, caused by past operating practices.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Occidental Petroleum Corporation

February 5, 2013

Page 8

Occidental has informed us that they are not aware of any legal, regulatory, political, environmental or economic obstacles that currently are expected to materially impact their ability to recover the estimated proved reserves for the properties reviewed by us.

Data Reviewed in Conducting the Third Party Reserves Process Review

Occidental has informed us that they have furnished or otherwise made available to us all of the material accounts, records, geological and engineering data, and reports and other data required for this review. In conducting our process review of Occidental’s estimates of proved reserves, forecasts of future production and income, we have reviewed data used by Occidental with respect to property interests owned or otherwise held, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and processing fees, ad valorem and production taxes, recompletion and development costs, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data utilized by Occidental. We consider the factual data utilized by Occidental to be appropriate and sufficient for the purpose of our review of the methods and analytical procedures utilized by the engineering and geological staff of Occidental for estimating the proved reserves volumes and preparing the economic evaluations.

Reserves Process Review Opinion

We found no bias in the utilization and analysis of data in proved reserves estimates for these properties. Furthermore, we found the estimation process incorporated all pertinent data, utilized a thorough and detailed analytical approach and was supported by a well documented audit trail.

We consider the assumptions, data, methods and analytical procedures used by Occidental and as reviewed by us appropriate for the purpose thereof, and we have used all such methods and procedures that we consider necessary and appropriate under the circumstances to render the conclusions set forth herein.

Based on our review, including the data, technical processes and interpretations presented by Occidental, it is our opinion that the overall procedures and methodologies utilized by Occidental in estimating the proved reserves volumes, documenting the changes in reserves from prior estimates, preparing the economic evaluations and determining the reserves classifications for the reviewed properties comply with the SEC regulations as of December 31, 2012. Ryder Scott has not been engaged to render an opinion as to the reasonableness of reserves quantities reported by Occidental.

Standards of Independence and Professional Qualification

Ryder Scott is an employee-owned independent petroleum engineering consulting firm. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. No single client or job represents a material portion of our annual revenue. These factors allow us to maintain our independence and objectivity in the performance of our services.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Occidental Petroleum Corporation

February 5, 2013

Page 9

Ryder Scott requires that staff engineers and geoscientists receive professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.

We are independent petroleum engineers with respect to Occidental. Neither we nor any of our employees have any interest in the subject properties and neither the employment to do this work nor the compensation is contingent on the results of our review.

The results of the reserves process review, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing the review of the reserves information discussed in this report, are included as an attachment to this letter.

Terms of Usage

The results of our third party reserves process review, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and are intended for public disclosure as an exhibit in filings made with the SEC by Occidental.

Occidental makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, Occidental has certain registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 10-K is incorporated by reference. We have consented to the incorporation by reference in the registration statements on Form S-3 and Form S-8 of Occidental of the references to our name as well as to the references to our third party report for Occidental, which appear in the December 31, 2012 annual report on Form 10-K of Occidental, the inclusion in that Form 10-K of such references and the filing of such report as an exhibit to such 10-K. Our written consent for such use is included as a separate exhibit to the filings made with the SEC by Occidental.

We have provided Occidental with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by Occidental and the original signed report letter, the original signed report letter shall control and supersede the digital version.

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

Very truly yours,

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

\s\ Jennifer Fitzgerald

Jennifer A. Fitzgerald, P.E.

TBPE License No. 100572

Vice President

[SEAL]

JAF (FPR)/pl

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Jennifer A. Fitzgerald was the primary technical person responsible for overseeing the reserves audit conducted by Ryder Scott of the estimates of reserves presented herein.

Mrs. Fitzgerald, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 2006, is a Vice President responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mrs. Fitzgerald served in a number of engineering positions with ExxonMobil. For more information regarding Mrs. Fitzgerald’s geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Experience/Employees.

Mrs. Fitzgerald earned a Bachelor of Science degree in Chemical Engineering from University of Illinois Urbana-Champaign in 2001 and is a registered Professional Engineer in the State of Texas. She is also a member of the Society of Petroleum Evaluation Engineers and Society of Petroleum Engineers. She currently serves as the Chairman of the Houston Chapter of the Society of Petroleum Evaluation Engineers.

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mrs. Fitzgerald fulfills. As part of her 2012 continuing education hours, Mrs. Fitzgerald attended 9hours of formalized training including the 2012 RSC Reserves Conference and various professional society presentations specifically relating to the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register. Mrs. Fitzgerald attended an additional 12.5 hours of formalized external training during 2012 covering such topics as reservoir engineering, geoscience and petroleum economics evaluation methods, procedures and software and ethics for consultants. She also presented presentations at the 2012 RSC Reserves Conference, the 2012 North American Petroleum Accounting Conference (NAPAC), and the 2012 National Oil and Gas Reserves Conference held by AICPA/PDI relating to the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register. Mrs. Fitzgerald also previously attended the one and two day short courses presented by Dr. John Lee specific to the new SEC regulations.

Based on her educational background, professional training and more than 11 years of practical experience in the estimation and evaluation of petroleum reserves, Mrs. Fitzgerald has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

PREAMBLE

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.

Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.

Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale. Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

Page 2

centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.

Reserves do not include quantities of petroleum being held in inventory.

Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.

RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:

Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

Page 3

PROVED RESERVES (SEC DEFINITIONS) CONTINUED

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)

Sponsored and Approved by:

SOCIETY OF PETROLEUM ENGINEERS (SPE)

WORLD PETROLEUM COUNCIL (WPC)

AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)

SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)

Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).

DEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:

Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Developed Producing (SPE-PRMS Definitions)

While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

Developed Producing Reserves

Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate.

Improved recovery reserves are considered producing only after the improved recovery project is in operation.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

Page 2

Developed Non-Producing

Developed Non-Producing Reserves include shut-in and behind-pipe reserves.

Shut-In

Shut-in Reserves are expected to be recovered from:

(1) completion intervals which are open at the time of the estimate, but which have not started producing;

(2) wells which were shut-in for market conditions or pipeline connections; or

(3) wells not capable of production for mechanical reasons.

Behind-Pipe

Behind-pipe Reserves are expected to be recovered from zones in existing wells, which will require additional completion work or future re-completion prior to start of production.

In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

UNDEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:

Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in [Regulation S-X §210.4-10(a)(2)], or by other evidence using reliable technology establishing reasonable certainty.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

XML

FAIR VALUE MEASUREMENTS (Tables)

12 Months Ended

Dec. 31, 2012

FAIR VALUE MEASUREMENTS

Assets and liabilities measured at fair value on a recurring basis (in millions)

	Fair Value Measurements at December 31, 2012 Using						Netting and			Total
Description	Level 1		Level 2		Level 3		Collateral (a)			Fair Value
Assets:
Commodity derivatives	$	107	$	312	$	—	$	(301	)	$	118
Liabilities:
Commodity derivatives	$	99	$	398	$	—	$	(371	)	$	126

	Fair Value Measurements at December 31, 2011 Using						Netting and			Total
Description	Level 1		Level 2		Level 3		Collateral (a)			Fair Value
Assets:
Commodity derivatives	$	310	$	640	$	—	$	(758	)	$	192
Liabilities:
Commodity derivatives	$	311	$	652	$	—	$	(782	)	$	181

(a) Represents the impact of netting assets, liabilities and collateral when a legal right of offset exists.

XML

DERIVATIVES (Details 4) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Gross fair value of derivative assets and liabilities outstanding
Less: counterparty netting and cash collateral, asset	$ (301)	$ (758)
Less: counterparty netting and cash collateral, liability	(371)	(782)
Total net fair value, asset	118	192
Total net fair value, liability	126	181
Payables in respect of collateral received netted with derivative assets	25	42
Receivables in respect of collateral paid netted with derivative liabilities	95	66
Collateral deposited with clearinghouses and brokers	116	173
Credit risk contingent features
Net derivative liabilities with credit-risk-related contingent features	34	58
Amount of collateral posted	64	27
Commodity Contracts
Gross fair value of derivative assets and liabilities outstanding
Commodity contract derivative asset, gross	419	950
Commodity contract derivative liability, gross	497	963
Cash-flow hedges | Commodity Contracts
Gross fair value of derivative assets and liabilities outstanding
Commodity contract derivative asset, gross	11	44
Commodity contract derivative liability, gross	2	5
Cash-flow hedges | Commodity Contracts | Other current assets
Gross fair value of derivative assets and liabilities outstanding
Commodity contract derivative asset, gross	11	41
Cash-flow hedges | Commodity Contracts | Long-term receivables and other assets, net
Gross fair value of derivative assets and liabilities outstanding
Commodity contract derivative asset, gross		3
Cash-flow hedges | Commodity Contracts | Accrued liabilities
Gross fair value of derivative assets and liabilities outstanding
Commodity contract derivative liability, gross	1	5
Cash-flow hedges | Commodity Contracts | Deferred credits and other liabilities
Gross fair value of derivative assets and liabilities outstanding
Commodity contract derivative liability, gross	1
Not designated as hedging instruments | Commodity Contracts
Gross fair value of derivative assets and liabilities outstanding
Commodity contract derivative asset, gross	408	906
Commodity contract derivative liability, gross	495	958
Not designated as hedging instruments | Commodity Contracts | Other current assets
Gross fair value of derivative assets and liabilities outstanding
Commodity contract derivative asset, gross	386	835
Not designated as hedging instruments | Commodity Contracts | Long-term receivables and other assets, net
Gross fair value of derivative assets and liabilities outstanding
Commodity contract derivative asset, gross	22	71
Not designated as hedging instruments | Commodity Contracts | Accrued liabilities
Gross fair value of derivative assets and liabilities outstanding
Commodity contract derivative liability, gross	479	887
Not designated as hedging instruments | Commodity Contracts | Deferred credits and other liabilities
Gross fair value of derivative assets and liabilities outstanding
Commodity contract derivative liability, gross	$ 16	$ 71

XML

LONG-TERM DEBT (Details 2) (Credit Facility, USD $) In Billions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Oct. 31, 2011
Credit Facility
Debt instrument
Maximum amount of credit facility available in the form of letters of credit		$ 1.0
Average annual facility fee as percent of the total commitment amounts	0.08%
Credit Facility, maximum borrowing capacity	$ 2.0

XML

ENVIRONMENTAL LIABILITIES AND EXPENDITURES (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012 Y site	Dec. 31, 2011 site	Dec. 31, 2010 site	Dec. 31, 2009
ENVIRONMENTAL LIABILITIES AND EXPENDITURES
Environmental remediation reserves, current, included in accrued liabilities	$ 80	$ 79	$ 79
Environmental remediation reserves, noncurrent, included in deferred credits and other liabilities - other	264	281	287
Environmental remediation reserves.
Number of Sites	161	160	170
Environmental remediation reserves	344	360	366	403
Environmental reserves, exceeding $ ten million, threshold value	10
Environmental reserves, exceeding $ ten million, number of sites	12
Environmental reserves, range between zero to $ one million site category, number of sites	112
Period of expending first half of environmental reserves (in years)	4
Minimum period of expending second half of environmental reserves (in years)	10
Environmental remediation additional loss range	375
Environmental costs, including certain estimates by segment
Operating Expenses	250	247	193
Capital Expenditures	152	140	104
Low end of range
Environmental remediation reserves.
Environmental reserves, range between zero to $ one million site category	0
High end of range
Environmental remediation reserves.
Environmental reserves, range between zero to $ one million site category	1
Oil and Gas
Environmental costs, including certain estimates by segment
Operating Expenses	160	158	108
Capital Expenditures	122	110	72
Chemical
Environmental costs, including certain estimates by segment
Operating Expenses	70	68	72
Capital Expenditures	18	15	19
Midstream, Marketing and Other
Environmental costs, including certain estimates by segment
Operating Expenses	20	21	13
Capital Expenditures	12	15	13
Corporate
Environmental costs, including certain estimates by segment
Remediation Expenses	56	52	25
NPL sites
Environmental remediation reserves.
Number of Sites	35	36	38
Environmental remediation reserves	54	63	56
Percentage of environmental reserves accounted for by associated sites	73.00%
Number of sites indemnified by third party	14
Number of sites with significant environmental remediation reserves	2
Third-party sites
Environmental remediation reserves.
Number of Sites	75	73	83
Environmental remediation reserves	84	88	91
Percentage of environmental reserves accounted for by associated sites	43.00%
Number of sites indemnified by third party	8
Number of sites not indemnified by third party	67
Number of sites with significant environmental remediation reserves	2
Occidental-operated sites
Environmental remediation reserves.
Number of Sites	22	22	20
Environmental remediation reserves	123	120	122
Percentage of environmental reserves accounted for by associated sites	70.00%
Number of sites with significant environmental remediation reserves	5
Closed or non-operated Occidental sites
Environmental remediation reserves.
Number of Sites	29	29	29
Environmental remediation reserves	$ 83	$ 89	$ 97
Percentage of environmental reserves accounted for by associated sites	55.00%
Number of sites with significant environmental remediation reserves	3

XML

INVENTORIES (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
INVENTORIES
Net carrying values of inventories valued under the LIFO method	$ 185	$ 176
Inventories
Raw materials	70	69
Materials and supplies	612	443
Finished goods	763	655
Inventories, Gross	1,445	1,167
LIFO reserve	(101)	(98)
Total	$ 1,344	$ 1,069

XML

ENVIRONMENTAL LIABILITIES AND EXPENDITURES (Tables)

12 Months Ended

Dec. 31, 2012

ENVIRONMENTAL LIABILITIES AND EXPENDITURES

Environmental loss contingencies by categories of sites

$ amounts in millions	2012			2011			2010
	Number of Sites	Reserve Balance		Number of Sites	Reserve Balance		Number of Sites	Reserve Balance
NPL sites	35	$	54	36	$	63	38	$	56
Third-party sites	75	84		73	88		83	91
Occidental-operated sites	22	123		22	120		20	122
Closed or non-operated Occidental sites	29	83		29	89		29	97
Total	161	$	344	160	$	360	170	$	366

Environmental reserve activity

In millions	2012			2011			2010
Balance — Beginning of Year	$	360		$	366		$	403
Remediation expenses and interest accretion	56			53			26
Changes from acquisitions/dispositions	—			14			3
Payments	(72		)	(73		)	(66		)
Balance — End of Year	$	344		$	360		$	366

Environmental cost for each segment

In millions	2012		2011		2010
Operating Expenses
Oil and Gas	$	160	$	158	$	108
Chemical	70		68		72
Midstream and Marketing	20		21		13
	$	250	$	247	$	193
Capital Expenditures
Oil and Gas	$	122	$	110	$	72
Chemical	18		15		19
Midstream and Marketing	12		15		13
	$	152	$	140	$	104
Remediation Expenses
Corporate	$	56	$	52	$	25

XML

LAWSUITS, CLAIMS, COMMITMENTS AND CONTINGENCIES (Details) (Capital Additions, USD $)	Dec. 31, 2012
Capital Additions
Long-term Purchase Commitment
Commitments for major fixed and determinable capital expenditures during 2013 and thereafter	$ 2,200,000,000
Purchase obligations
Total purchase obligations	8,700,000,000
Purchase obligations, due in fiscal year 2013	2,700,000,000
Purchase obligations, due in fiscal year 2014	1,400,000,000
Purchase obligations, due in fiscal year 2015	700,000,000
Purchase obligations, due in fiscal year 2016	500,000,000
Purchase obligations, due in fiscal year 2017	$ 400,000,000

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INDUSTRY SEGMENTS AND GEOGRAPHIC AREAS

12 Months Ended

Dec. 31, 2012

INDUSTRY SEGMENTS AND GEOGRAPHIC AREAS

INDUSTRY SEGMENTS AND GEOGRAPHIC AREAS

NOTE 16 INDUSTRY SEGMENTS AND GEOGRAPHIC AREAS

Occidental conducts its continuing operations through three segments: (1) oil and gas; (2) chemical; and (3) midstream and marketing.  The oil and gas segment explores for, develops and produces oil and condensate, NGLs, and natural gas.  The chemical segment mainly manufactures and markets basic chemicals and vinyls.  The midstream and marketing segment gathers, processes, transports, stores, purchases and markets oil, condensate, NGLs, natural gas, CO2 and power.  It also trades around its assets, including transportation and storage capacity, and trades oil, NGLs, gas and other commodities.  The segment also invests in entities that conduct similar activities.

Earnings of industry segments and geographic areas exclude income taxes, interest income, interest expense, environmental remediation expenses, unallocated corporate expenses and discontinued operations, but include gains and losses from dispositions of segment and geographic area assets and income from the segments’ equity investments.  Intersegment sales eliminate upon consolidation and are generally made at prices approximating those that the selling entity would be able to obtain in third-party transactions.

Identifiable assets are those assets used in the operations of the segments.  Corporate assets consist of cash, certain corporate receivables and PP&E, and an investment in the Joslyn, Canada oil sands project.

Industry Segments

In millions	Oil and Gas			Chemical			Midstream and Marketing			Corporate and Eliminations			Total
YEAR ENDED DECEMBER 31, 2012
Net sales	$	18,906	(a)	$	4,580	(b)	$	1,399	(c)	$	(713	)	$	24,172
Pretax operating profit (loss)	$	7,095	(d)	$	720		$	439		$	(501)	(f,h)	$	7,753
Income taxes	—			—			—			(3,118)		(g,h)	(3,118		)
Discontinued operations, net	—			—			—			(37		)	(37		)
Net income (loss) attributable to common stock	$	7,095		$	720		$	439		$	(3,656	)	$	4,598
Investments in unconsolidated entities	$	113		$	108		$	1,662		$	11		$	1,894
Property, plant and equipment additions, net (i)	$	8,282		$	365		$	1,612		$	91		$	10,350
Depreciation, depletion and amortization	$	3,933		$	345		$	206		$	27		$	4,511
Total assets	$	44,004		$	3,854		$	12,762		$	3,590		$	64,210
YEAR ENDED DECEMBER 31, 2011
Net sales	$	18,419	(a)	$	4,815	(b)	$	1,447	(c)	$	(742	)	$	23,939
Pretax operating profit (loss)	$	10,241	(d)	$	861		$	448		$	(709)	(f,h)	$	10,841	(d)
Income taxes	—			—			—			(4,201)		(g,h)	(4,201		)
Discontinued operations, net	—			—			—			131			131
Net income (loss) attributable to common stock	$	10,241	(d)	$	861		$	448		$	(4,779	)	$	6,771
Investments in unconsolidated entities	$	128		$	121		$	1,812		$	11		$	2,072
Property, plant and equipment additions, net (i)	$	6,192		$	241		$	1,120		$	51		$	7,604
Depreciation, depletion and amortization	$	3,064		$	330		$	173		$	24		$	3,591
Total assets	$	38,967		$	3,754		$	11,962		$	5,361		$	60,044
YEAR ENDED DECEMBER 31, 2010
Net sales	$	14,276	(a)	$	4,016	(b)	$	1,471	(c)	$	(718	)	$	19,045
Pretax operating profit (loss)	$	7,151	(d,e)	$	438		$	472		$	(497)	(f,h)	$	7,564	(d,e)
Income taxes	—			—			—			(2,995)		(g,h)	(2,995		)
Discontinued operations, net	—			—			—			(39		)	(39		)
Net income (loss) attributable to common stock	$	7,151	(d,e)	$	438		$	472		$	(3,531	)	$	4,530	(e)
Investments in unconsolidated entities	$	123		$	135		$	1,770		$	11		$	2,039
Property, plant and equipment additions, net (i)	$	3,211		$	248		$	537		$	38		$	4,034
Depreciation, depletion and amortization	$	2,668		$	321		$	142		$	22		$	3,153
Total assets	$	31,855		$	3,755		$	10,445		$	6,377	(j)	$	52,432
(See footnotes on next page)

Footnotes:

(a) Oil sales represented approximately 90 percent, 87 percent and 86 percent of the oil and gas segment net sales for the years ended December 31, 2012, 2011 and 2010, respectively.

(b) Net sales for the chemical segment comprised the following products:

	Basic Chemicals		Vinyls		Other Chemicals
Year ended December 31, 2012	57	%	40	%	3	%
Year ended December 31, 2011	58	%	39	%	3	%
Year ended December 31, 2010	57	%	40	%	3	%

(c) Net sales for the midstream and marketing segment comprised the following:

	Gas Processing		Power		Marketing, Trading, Transportation and other
Year ended December 31, 2012	59	%	20	%	21	%
Year ended December 31, 2011	64	%	27	%	9	%
Year ended December 31, 2010	52	%	27	%	21	%

(d) The 2012 amount includes pre-tax charges of $1.7 billion for the impairment of domestic gas assets and related items.  The 2011 amount includes pre-tax charges of $35 million related to exploration write-offs in Libya and $29 million related to a Colombian net worth tax, and a pre-tax gain for the sale of an interest in a Colombian pipeline of $22 million.  The 2010 amount includes a $275 million pre-tax charge for asset impairments, predominantly of gas properties in the Rocky Mountain region.

(e) Includes amounts attributable to common stock after deducting a noncontrolling interest amount of $72 million.

(f) Includes unallocated net interest expense, administration expense, environmental remediation and other pre-tax items noted in footnote (h) below.

(g) Includes all foreign and domestic income taxes from continuing operations.

(h) Includes the following significant items affecting earnings for the years ended December 31:

Benefit (Charge)  (In millions)	2012			2011			2010
CORPORATE
Pre-tax operating profit (loss)
Premium on debt extinguishments	$	—		$	(163	)	$	—
Litigation reserves	(20		)	—			—
	$	(20	)	$	(163	)	$	—
Income taxes
State income tax charge	$	—		$	(33	)	$	—
Foreign tax credit carryforwards	—			—			80
Tax effect of pre-tax adjustments *	636			50			100
	$	636		$	17		$	180

*   Amounts represent the tax effect of all pre-tax adjustments listed, as well as those in footnote (d).

(i) Includes capital expenditures and capitalized interest, but excludes purchases of assets, net.  Also includes amounts attributable to the noncontrolling interest in a Colombian subsidiary for 2010.

(j) Includes Argentine assets, which were classified as held for sale.

GEOGRAPHIC AREAS

In millions

	Net sales (a)						Property, plant and equipment, net
For the years ended December 31,	2012		2011		2010		2012		2011		2010
United States	$	15,359	$	15,040	$	12,151	$	40,786	$	36,283	$	28,571
Foreign
Qatar	3,356		3,432		2,677		2,676		2,735		2,823
Oman	2,578		2,500		1,666		2,353		2,143		1,967
Colombia	1,027		1,054		999		1,041		854		715
Yemen	407		907		766		199		245		347
Bahrain	215		187		100		688		477		222
United Arab Emirates	—		—		—		2,104		971		1
Other Foreign	1,230		819		686		2,217		1,976		1,890
Total Foreign	8,813		8,899		6,894		11,278		9,401		7,965
Total	$	24,172	$	23,939	$	19,045	$	52,064	$	45,684	$	36,536

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

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LEASE COMMITMENTS (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Future net minimum operating lease payments
Operating lease, 2013	$ 158
Operating lease, 2014	105
Operating lease, 2015	106
Operating lease, 2016	88
Operating lease, 2017	59
Operating lease, Thereafter	460
Total minimum lease payments	976
Future receivable sublease rentals	3
Sublease rental amounts, 2013	2
Sublease rental amounts, 2014	1
Rental expense for operating leases, net of sublease rental income	176	179	170
Sublease income	$ 4	$ 4	$ 4

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ACQUISITIONS, DISPOSITIONS AND OTHER TRANSACTIONS (Details) (USD $)	1 Months Ended				3 Months Ended
	Nov. 30, 2012 mi	Nov. 30, 2012 Maximum bbl	Dec. 31, 2012 Domestic Oil and Gas Properties	Dec. 31, 2011 Producing properties in South Texas	Mar. 31, 2011 Al Hosn gas project Y	May 31, 2011 Al Hosn gas project	Dec. 31, 2011 Domestic Oil and Gas Properties
Acquisitions, dispositions and other transactions
Length of BridgeTex Pipeline	450
BridgeTex Pipeline, crude oil transportation capacity per day		300,000
Cash paid on acquisition			$ 2,300,000,000	$ 1,800,000,000			$ 2,600,000,000
Percentage of interest acquired in oil and gas properties and projects					40.00%
Term of joint venture agreement (in years)					30
Pre-acquisition development expenditures						$ 500,000,000

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RETIREMENT AND POSTRETIREMENT BENEFIT PLANS (Tables)

12 Months Ended

Dec. 31, 2012

RETIREMENT AND POSTRETIREMENT BENEFIT PLANS

Components of amounts recognized in the consolidated balance sheets (in millions)

	Pension Benefits						Postretirement Benefits
As of December 31,	2012			2011			2012			2011
Amounts recognized in the consolidated balance sheet:
Other assets	$	24		$	24		$	—		$	—
Accrued liabilities	(4		)	(5		)	(59		)	(47		)
Deferred credits and other liabilities — other	(136		)	(136		)	(1,068		)	(1,045		)
	$	(116	)	$	(117	)	$	(1,127	)	$	(1,092	)

After-tax balances included in AOCI (in millions)

	Pension Benefits				Postretirement Benefits
As of December 31,	2012		2011		2012		2011
AOCI included the following after-tax balances:
Net loss	$	134	$	146	$	324	$	331
Prior service cost	1		2		2		2
	$	135	$	148	$	326	$	333

Funding status of Occidental's plans (in millions)

For the years ended December 31,
Changes in benefit obligation:
Benefit obligation — beginning of year	$	592		$	615		$	1,092		$	991
Service cost — benefits earned during the period	13			12			25			22
Interest cost on projected benefit obligation	27			29			42			45
Actuarial loss	46			49			26			81
Foreign currency exchange rate (gain) loss	2			(5		)	—			—
Benefits paid	(57		)	(51		)	(58		)	(47		)
Settlements	(8		)	(57		)	—			—
Benefit obligation — end of year	$	615		$	592		$	1,127		$	1,092
Changes in plan assets:
Fair value of plan assets — beginning of year	$	475		$	495		$	—		$	—
Actual return on plan assets	61			13			—			—
Foreign currency exchange rate gain (loss)	(3		)	(3		)	—			—
Employer contributions	31			78			—			—
Benefits paid	(57		)	(51		)	—			—
Settlements	(8		)	(57		)	—			—
Fair value of plan assets — end of year	$	499		$	475		$	—		$	—
Unfunded status:	$	(116	)	$	(117	)	$	(1,127	)	$	(1,092	)

Schedule of 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 and plan assets in excess of the accumulated benefit obligation

	Accumulated Benefit Obligation in Excess of Plan Assets				Plan Assets in Excess of Accumulated Benefit Obligation
As of December 31, (in millions)	2012		2011		2012		2011
Projected Benefit Obligation	$	305	$	361	$	310	$	231
Accumulated Benefit Obligation	$	278	$	334	$	305	$	227
Fair Value of Plan Assets	$	171	$	226	$	328	$	249

Components of the net periodic benefit cost

	Pension Benefits									Postretirement Benefits
For the years ended December 31, (in millions)	2012			2011			2010			2012		2011		2010
Net periodic benefit costs:
Service cost — benefits earned during the period	$	13		$	12		$	16		$	25	$	22	$	19
Interest cost on benefit obligation	27			29			30			42		45		44
Expected return on plan assets	(31		)	(33		)	(31		)	—		—		—
Recognized actuarial loss	19			13			15			37		31		27
Other costs and adjustments	17			—			10			1		1		1
Net periodic benefit cost	$	45		$	21		$	40		$	105	$	99	$	91

Weighted-average assumptions used to determine Occidental's benefit obligation and net periodic benefit cost for domestic plans

	Pension Benefits				Postretirement Benefits
For the years ended December 31,	2012		2011		2012		2011
Benefit Obligation Assumptions:
Discount rate	3.59	%	4.12	%	3.89	%	4.12	%
Rate of compensation increase	4.00	%	4.00	%	—		—
Net Periodic Benefit Cost Assumptions:
Discount rate	4.12	%	4.74	%	4.12	%	4.74	%
Assumed long term rate of return on assets	6.50	%	6.50	%	—		—
Rate of compensation increase	4.00	%	4.00	%	—		—

Fair values of Occidental's pension plan assets by asset category (in millions)

	Fair Value Measurements at December 31, 2012 Using
Description	Level 1		Level 2		Level 3		Total
Asset Class:
U.S. government securities	$	24	$	—	$	—	$	24
Corporate bonds (a)	—		83		—		83
Common/collective trusts (b)	—		11		—		11
Mutual funds:
Bond funds	84		—		—		84
Blend funds	106		—		—		106
Value and growth funds	5		—		—		5
Common and preferred stocks (c)	146		—		—		146
Other	—		35		11		46
Total pension plan assets (d)	$	365	$	129	$	11	$	505

	Fair Value Measurements at December 31, 2011 Using
Description	Level 1		Level 2		Level 3		Total
Asset Class:
U.S. government securities	$	22	$	—	$	—	$	22
Corporate bonds (a)	—		83		—		83
Common/collective trusts (b)	—		14		—		14
Mutual funds:
Bond funds	84		—		—		84
Blend funds	97		—		—		97
Value and growth funds	5		—		—		5
Common and preferred stocks (c)	131		—		—		131
Other	—		34		12		46
Total pension plan assets (d)	$	339	$	131	$	12	$	482

(a) This category represents investment grade bonds of U.S. and non-U.S. issuers from diverse industries.

(b) This category includes investment funds that primarily invest in U.S. and non-U.S. common stocks and fixed-income securities.

(c) This category represents direct investments in common and preferred stocks from diverse U.S. and non-U.S. industries.

(d) Amounts exclude net payables of approximately $6 million and $7 million as of December 31, 2012 and 2011, respectively.

Estimated future benefit payments, which reflect expected future service, as appropriate

For the years ended December 31, (in millions)	Pension Benefits		Postretirement Benefits
2013	$	40	$	50
2014	$	44	$	51
2015	$	41	$	52
2016	$	46	$	53
2017	$	42	$	54
2018 — 2022	$	230	$	294

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DERIVATIVES (Details 2) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
Net After-tax Derivative Activity recorded in AOCI
Beginning balance-AOCI	$ 1		$ (111)
Unrealized gains recognized in AOCI	16	[1]	14	[1]	37	[1]
(Gains) losses reclassified to income	(24)	[2]	98	[2]	83	[2]
Ending balance - AOCI	(7)		1		(111)
Pre-tax derivative activity
Unrealized gains recognized in AOCI	25		20
(Gains) losses reclassified to income	$ (38)		$ 154

[1] Net of tax of $(9), $(7) and $(20) in 2012, 2011 and 2010, respectively.

[2] Net of tax of $14, $(56) and $(47) in 2012, 2011 and 2010, respectively.

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Schedule II - Valuation and Qualifying Accounts (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Valuation and qualifying accounts
Balance at Beginning of Period	$ 558	$ 559	$ 629
Charged to Costs and Expenses	113	90	46
Charged to Other Accounts		14	9
Deductions	(98)	(105)	(125)
Balance at End of Period	573	558	559
Valuation and qualifying accounts, classified as current	98	100	102
Allowance for doubtful accounts
Valuation and qualifying accounts
Balance at Beginning of Period		19	30
Charged to Costs and Expenses			(9)
Deductions		(3)	(2)
Balance at End of Period	16	16	19
Environmental
Valuation and qualifying accounts
Balance at Beginning of Period	360	366	403
Charged to Costs and Expenses	56	53	26
Charged to Other Accounts		14	3
Deductions	(72)	(73)	(66)
Balance at End of Period	344	360	366
Litigation, tax and other reserves
Valuation and qualifying accounts
Balance at Beginning of Period	198	193	226
Charged to Costs and Expenses	57	37	20
Charged to Other Accounts			6
Deductions	(26)	(32)	(59)
Balance at End of Period	$ 229	$ 198	$ 193

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RETIREMENT AND POSTRETIREMENT BENEFIT PLANS (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
DEFINED CONTRIBUTION PLANS
Accrued liabilities for the supplemental retirement plan	$ 145	$ 126
Expenses under provisions of defined contribution and supplemental retirement plan	137	110	101
Defined Benefit Plan Disclosure
Total benefit costs including postretirement costs	218	194	180
AOCI included the following after-tax balances
AOCI after-tax balances	461	475
FAIR VALUE OF PENSION AND POSTRETIREMENT PLAN ASSETS
Target allocation of plan assets, equity securities (as a percent)	60.00%
Target allocation of plan assets, debt securities (as a percent)	40.00%
Pension Benefit
Amounts recognized in the consolidated balance sheets
Other assets	24	24
Accrued liabilities	(4)	(5)
Deferred credits and other liabilities - other	(136)	(136)
Amounts recognized in the consolidated balance sheets, total	(116)	(117)
AOCI included the following after-tax balances
Net loss	134	146
Prior service cost	1	2
AOCI after-tax balances	135	148
Changes in benefit obligation:
Benefit obligation - beginning of year	592	615
Service cost - benefits earned during the period	13	12	16
Interest cost on projected benefit obligation	27	29	30
Actuarial loss	46	49
Foreign currency exchange rate (gain) loss	2	(5)
Benefits paid	(57)	(51)
Settlements	(8)	(57)
Benefit obligation - end of year	615	592	615
Changes in plan assets:
Fair value of plan assets - beginning of year	475	495
Actual return on plan assets	61	13
Foreign currency exchange rate gain (loss)	(3)	(3)
Employer contributions	31	78
Benefits paid	(57)	(51)
Settlements	(8)	(57)
Fair value of plan assets - end of year	499	475	495
Unfunded status:	(116)	(117)
Pension plans with accumulated benefit obligations in excess of plan assets
Pension plans with accumulated benefit obligations in excess of plan assets, projected benefit obligation	305	361
Pension plans with accumulated benefit obligations in excess of plan assets, accumulated benefit obligation	278	334
Pension plans with accumulated benefit obligations in excess of plan assets, fair value of plan assets	171	226
Pension plans with plan assets in excess of accumulated benefit obligations
Pension plans with plan assets in excess of accumulated benefit obligations, projected benefit obligation	310	231
Pension plans with plan assets in excess of accumulated benefit obligations, accumulated benefit obligation	305	227
Pension plans with plan assets in excess of accumulated benefit obligations, fair value of plan assets	328	249
Net periodic benefit costs:
Service cost - benefits earned during the period	13	12	16
Interest cost on projected benefit obligation	27	29	30
Expected return on plan assets	(31)	(33)	(31)
Recognized actuarial loss	19	13	15
Other costs and adjustments	17		10
Net periodic benefit cost	45	21	40
Amounts that will be amortized from accumulated other comprehensive income (Loss) in next fiscal year
Estimated net loss that will be amortized from AOCI into net periodic benefit cost over the next fiscal year	17
Estimated prior service cost that will be amortized from AOCI into net periodic benefit cost over the next fiscal year	0
Benefit Obligation Assumptions:
Discount rate (as a percent)	3.59%	4.12%
Rate of compensation increase (as a percent)	4.00%	4.00%
Net Periodic Benefit Cost Assumptions:
Discount rate (as a percent)	4.12%	4.74%
Assumed long term rate of return on assets (as a percent)	6.50%	6.50%
Rate of compensation increase (as a percent)	4.00%	4.00%
Domestic Pension Benefits
Defined Benefit Plan Disclosure
Number of employees accruing benefits under defined benefit plans	1,000
Foreign Pension Plans
Defined Benefit Plan Disclosure
Number of employees accruing benefits under defined benefit plans	1,600
Net Periodic Benefit Cost Assumptions:
Assumed long term rate of return on assets (as a percent)	6.50%	5.80%
Foreign Pension Plans | High end of range
Net Periodic Benefit Cost Assumptions:
Discount rate (as a percent)	10.00%	10.00%
Rate of compensation increase (as a percent)	10.00%
Foreign Pension Plans | Low end of range
Net Periodic Benefit Cost Assumptions:
Discount rate (as a percent)	1.50%	1.50%
Rate of compensation increase (as a percent)	1.50%
Postretirement Benefit
Amounts recognized in the consolidated balance sheets
Accrued liabilities	(59)	(47)
Deferred credits and other liabilities - other	(1,068)	(1,045)
Amounts recognized in the consolidated balance sheets, total	(1,127)	(1,092)
AOCI included the following after-tax balances
Net loss	324	331
Prior service cost	2	2
AOCI after-tax balances	326	333
Changes in benefit obligation:
Benefit obligation - beginning of year	1,092	991
Service cost - benefits earned during the period	25	22	19
Interest cost on projected benefit obligation	42	45	44
Actuarial loss	26	81
Benefits paid	(58)	(47)
Benefit obligation - end of year	1,127	1,092	991
Changes in plan assets:
Unfunded status:	(1,127)	(1,092)
Net periodic benefit costs:
Service cost - benefits earned during the period	25	22	19
Interest cost on projected benefit obligation	42	45	44
Recognized actuarial loss	37	31	27
Other costs and adjustments	1	1	1
Net periodic benefit cost	105	99	91
Amounts that will be amortized from accumulated other comprehensive income (Loss) in next fiscal year
Estimated net loss that will be amortized from AOCI into net periodic benefit cost over the next fiscal year	37
Estimated prior service cost that will be amortized from AOCI into net periodic benefit cost over the next fiscal year	1
Benefit Obligation Assumptions:
Discount rate (as a percent)	3.89%	4.12%
Net Periodic Benefit Cost Assumptions:
Discount rate (as a percent)	4.12%	4.74%
Assumed health care cost trend rates
Consumer Price Index (CPI) increase (as a percent)	2.39%	2.04%
Projected annual rates of health care cost trend rates (as a percent)	8.50%
Projected ultimate health care cost trend rates (as a percent)	6.00%
Year the projected health care cost trend rate reaches ultimate trend rate	2017
Increase (decrease) in projected annual rates of health care cost trend rates (as a percent)	(0.50%)
Effect of 1-percent increase or a 1-percent decrease in these assumed health care cost trend rates
Effect of 1-percent increase in assumed health care cost trend rates on postretirement benefit obligation	44
Effect of 1-percent decrease in assumed health care cost trend rates on postretirement benefit obligation	$ 37

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LONG-TERM DEBT (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended	12 Months Ended					1 Months Ended			1 Months Ended			1 Months Ended		1 Months Ended						1 Months Ended			1 Months Ended			1 Months Ended		1 Months Ended											1 Months Ended
	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2012 Dolphin Energy	Dec. 31, 2011 Dolphin Energy	Dec. 31, 2010 4.10% senior notes due 2021	Dec. 31, 2012 4.10% senior notes due 2021	Dec. 31, 2011 4.10% senior notes due 2021	Aug. 31, 2011 1.75% senior notes due 2017	Dec. 31, 2012 1.75% senior notes due 2017	Dec. 31, 2011 1.75% senior notes due 2017	Jun. 30, 2012 2.70% senior notes due 2023	Dec. 31, 2012 2.70% senior notes due 2023	Mar. 31, 2011 7.0% senior notes due 2013	Aug. 31, 2011 3.125% senior notes due 2022	Dec. 31, 2012 3.125% senior notes due 2022	Dec. 31, 2011 3.125% senior notes due 2022	Dec. 31, 2012 4.125% senior notes due 2016	Dec. 31, 2011 4.125% senior notes due 2016	Dec. 31, 2010 2.5% senior notes due 2016	Dec. 31, 2012 2.5% senior notes due 2016	Dec. 31, 2011 2.5% senior notes due 2016	Dec. 31, 2010 1.45% senior notes due 2013	Dec. 31, 2012 1.45% senior notes due 2013	Dec. 31, 2011 1.45% senior notes due 2013	Jun. 30, 2012 1.50% senior notes due 2018	Dec. 31, 2012 1.50% senior notes due 2018	Mar. 31, 2011 6.75% senior notes due 2012	Dec. 31, 2012 8.45% senior notes due 2029	Dec. 31, 2011 8.45% senior notes due 2029	Dec. 31, 2012 9.25% senior debentures due 2019	Dec. 31, 2011 9.25% senior debentures due 2019	Dec. 31, 2012 7.2% senior debentures due 2028	Dec. 31, 2011 7.2% senior debentures due 2028	Dec. 31, 2012 Variable rate bonds due 2030 (0.13% and 0.11% as of December 31, 2012 and 2011, respectively)	Dec. 31, 2011 Variable rate bonds due 2030 (0.13% and 0.11% as of December 31, 2012 and 2011, respectively)	Dec. 31, 2012 8.75% medium-term notes due 2023	Dec. 31, 2011 8.75% medium-term notes due 2023	Aug. 31, 2011 1.75% senior notes due 2017, 3.125% senior notes due 2022	Dec. 31, 2010 1.45% senior notes due 2013, 2.5% senior notes due 2016 and 4.10% senior notes due 2021	Jun. 30, 2012 2.70% senior notes due 2023, 1.50% senior notes due 2018
Debt instrument
Variable interest rate (as a percent)																																				0.13%	0.11%
Long-term debt, gross		$ 7,654	$ 5,904					$ 1,300	$ 1,300		$ 1,250	$ 1,250		$ 1,250			$ 900	$ 900	$ 750	$ 750		$ 700	$ 700		$ 600	$ 600		$ 500		$ 116	$ 116	$ 116	$ 116	$ 82	$ 82	$ 68	$ 68	$ 22	$ 22
Unamortized discount, net		(31)	(33)
Current maturities		(600)
Total long-term debt		7,023	5,871
Debt instrument interest rate stated percentage								4.10%	4.10%		1.75%	1.75%		2.70%			3.125%	3.125%	4.125%	4.125%		2.50%	2.50%		1.45%	1.45%		1.50%		8.45%	8.45%	9.25%	9.25%	7.20%	7.20%			8.75%	8.75%
Debt instrument issued							1,300			1,250			1,250			900					700			600			500													2,150	2,600	1,750
Net proceeds from issuance of long-term debt		1,736	2,111	2,584																																				2,100	2,600	1,740
Face amount of notes redeemed															1,000														368
Pre-tax charge related to this redemption of notes	163
Notional amount of limited recourse guarantees with respect to Dolphin Energy's debt					$ 370	$ 300

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Consolidated Statements of Cash Flows (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
CASH FLOW FROM OPERATING ACTIVITIES
Net income	$ 4,598	$ 6,771	$ 4,602
Adjustments to reconcile net income to net cash provided by operating activities:
Discontinued operations, net	37	(131)	39
Depreciation, depletion and amortization of assets	4,511	3,591	3,153
Deferred income tax provision	1,128	1,436	406
Other noncash charges to income	195	190	231
Asset impairments and related items	1,751		275
Undistributed earnings from equity investments	(30)	(33)	(60)
Dry hole expenses	279	160	139
Changes in operating assets and liabilities:
Decrease (increase) in receivables	472	(360)	(929)
(Increase) decrease in inventories	(265)	(50)	(42)
Decrease in other current assets	127	95	210
(Decrease) increase in accounts payable and accrued liabilities	(1,086)	657	1,146
Increase (decrease) in current domestic and foreign income taxes	1	(174)	186
Other operating, net	(370)	154
Operating cash flow from continuing operations	11,348	12,306	9,356
Operating cash flow from discontinued operations, net of taxes	(36)	(25)	210
Net cash provided by operating activities	11,312	12,281	9,566
CASH FLOW FROM INVESTING ACTIVITIES
Capital expenditures	(10,226)	(7,518)	(3,940)
Payments for purchases of assets and businesses	(2,490)	(4,909)	(4,924)
Sales of assets, net	4	50	20
Other, net	57	(96)	(36)
Investing cash flow from continuing operations	(12,655)	(12,473)	(8,880)
Investing cash flow from discontinued operations		2,570	(415)
Net cash used by investing activities	(12,655)	(9,903)	(9,295)
CASH FLOW FROM FINANCING ACTIVITIES
Proceeds from long-term debt	1,736	2,111	2,584
Payments of long-term debt		(1,523)	(311)
Proceeds from issuance of common stock	85	50	10
Purchases of treasury stock	(583)	(274)	(67)
Contributions from (distributions to) noncontrolling interest	32	(121)
Cash dividends paid	(2,128)	(1,436)	(1,159)
Other, net	12	18	26
Net cash (used) provided by financing activities	(846)	(1,175)	1,083
(Decrease) increase in cash and cash equivalents	(2,189)	1,203	1,354
Cash and cash equivalents - beginning of year	3,781	2,578	1,224
Cash and cash equivalents - end of year	$ 1,592	$ 3,781	$ 2,578

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RETIREMENT AND POSTRETIREMENT BENEFIT PLANS (Details 2) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Pension Benefit
Defined Benefit Plan Disclosure
Fair value of plan assets	$ 499	$ 475	$ 495
Estimated future benefit payments
2013	40
2014	44
2015	41
2016	46
2017	42
2018 - 2022	230
Expected contribution to defined benefit pension plans during 2013	5
Postretirement Benefits
Estimated future benefit payments
2013	50
2014	51
2015	52
2016	53
2017	54
2018 - 2022	294
Pension Plan Assets - Gross | Pension Benefit
Defined Benefit Plan Disclosure
Fair value of plan assets	505	482
U.S. government securities | Pension Benefit
Defined Benefit Plan Disclosure
Fair value of plan assets	24	22
Corporate bonds | Pension Benefit
Defined Benefit Plan Disclosure
Fair value of plan assets	83	83
Common/collective trusts | Pension Benefit
Defined Benefit Plan Disclosure
Fair value of plan assets	11	14
Bond funds | Pension Benefit
Defined Benefit Plan Disclosure
Fair value of plan assets	84	84
Blend funds | Pension Benefit
Defined Benefit Plan Disclosure
Fair value of plan assets	106	97
Value and growth funds | Pension Benefit
Defined Benefit Plan Disclosure
Fair value of plan assets	5	5
Common and preferred stocks | Pension Benefit
Defined Benefit Plan Disclosure
Fair value of plan assets	146	131
Other | Pension Benefit
Defined Benefit Plan Disclosure
Fair value of plan assets	46	46
Net Payables | Pension Benefit
Defined Benefit Plan Disclosure
Fair value of plan assets	6	7
Level 1 | Pension Plan Assets - Gross | Pension Benefit
Defined Benefit Plan Disclosure
Fair value of plan assets	365	339
Level 1 | U.S. government securities | Pension Benefit
Defined Benefit Plan Disclosure
Fair value of plan assets	24	22
Level 1 | Bond funds | Pension Benefit
Defined Benefit Plan Disclosure
Fair value of plan assets	84	84
Level 1 | Blend funds | Pension Benefit
Defined Benefit Plan Disclosure
Fair value of plan assets	106	97
Level 1 | Value and growth funds | Pension Benefit
Defined Benefit Plan Disclosure
Fair value of plan assets	5	5
Level 1 | Common and preferred stocks | Pension Benefit
Defined Benefit Plan Disclosure
Fair value of plan assets	146	131
Level 2 | Pension Plan Assets - Gross | Pension Benefit
Defined Benefit Plan Disclosure
Fair value of plan assets	129	131
Level 2 | Corporate bonds | Pension Benefit
Defined Benefit Plan Disclosure
Fair value of plan assets	83	83
Level 2 | Common/collective trusts | Pension Benefit
Defined Benefit Plan Disclosure
Fair value of plan assets	11	14
Level 2 | Other | Pension Benefit
Defined Benefit Plan Disclosure
Fair value of plan assets	35	34
Level 3 | Pension Plan Assets - Gross | Pension Benefit
Defined Benefit Plan Disclosure
Fair value of plan assets	11	12
Level 3 | Other | Pension Benefit
Defined Benefit Plan Disclosure
Fair value of plan assets	$ 11	$ 12

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ACQUISITIONS, DISPOSITIONS AND OTHER TRANSACTIONS (Details 2) (BridgeTex, USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012 bbl
Acquisitions, dispositions and other transactions
Aggregate oil storage capacity of pipeline to be constructed	2,600,000
Percentage of ownership interest	50.00%
Money market mutual funds	$ 50
Magellan
Acquisitions, dispositions and other transactions
Percentage of interest acquired in oil and gas properties and projects	50.00%

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INVENTORIES (Tables)

12 Months Ended

Dec. 31, 2012

INVENTORIES

Inventories (in millions)

Balance at December 31, (in millions)	2012			2011
Raw materials	$	70		$	69
Materials and supplies	612			443
Finished goods	763			655
	1,445			1,167
LIFO reserve	(101		)	(98		)
Total	$	1,344		$	1,069

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)

12 Months Ended

Dec. 31, 2012

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Summary of the activity of capitalized exploratory well costs for continuing operations

In millions	2012			2011			2010
Balance — Beginning of Year	$	182		$	73		$	51
Additions to capitalized exploratory well costs pending the determination of proved reserves	400			334			112
Reclassifications to property, plant and equipment based on the determination of proved reserves	(407		)	(204		)	(73		)
Capitalized exploratory well costs charged to expense	(77		)	(21		)	(17		)
Balance — End of Year	$	98		$	182		$	73

Summary of the activity of the asset retirement obligation

For the years ended December 31, (in millions)	2012			2011
Beginning balance	$	1,089		$	800
Liabilities incurred - capitalized to PP&E	86			74
Liabilities settled and paid	(58		)	(53		)
Accretion expense	61			48
Acquisitions and other - capitalized to PP&E	50			177
Revisions to estimated cash flows - capitalized to PP&E	38			43
Ending balance	$	1,266		$	1,089

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ENVIRONMENTAL LIABILITIES AND EXPENDITURES (Details 2) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Environmental reserve activity
Balance - Beginning of Year	$ 360	$ 366	$ 403
Remediation expenses and interest accretion	56	53	26
Changes from acquisitions/dispositions		14	3
Payments	(72)	(73)	(66)
Balance - End of Year	$ 344	$ 360	$ 366

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ACQUISITIONS, DISPOSITIONS AND OTHER TRANSACTIONS (Details 3) (Libya activity, USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2011
Libya activity
Acquisitions, dispositions and other transactions
Capitalized and suspended exploration costs written off	$ 35

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LONG-TERM DEBT (Tables)

12 Months Ended

Dec. 31, 2012

LONG-TERM DEBT

Long-term debt

Balance at December 31, (in millions)	2012			2011
4.10% senior notes due 2021	$	1,300		$	1,300
1.75% senior notes due 2017	1,250			1,250
2.70% senior notes due 2023	1,250			—
3.125% senior notes due 2022	900			900
4.125% senior notes due 2016	750			750
2.5% senior notes due 2016	700			700
1.45% senior notes due 2013	600			600
1.50% senior notes due 2018	500			—
8.45% senior notes due 2029	116			116
9.25% senior debentures due 2019	116			116
7.2% senior debentures due 2028	82			82
Variable rate bonds due 2030 (0.13% and 0.11% as of December 31, 2012 and 2011, respectively)	68			68
8.75% medium-term notes due 2023	22			22
	7,654			5,904
Less:
Unamortized discount, net	(31		)	(33		)
Current maturities	(600		)	—
Total	$	7,023		$	5,871

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LEASE COMMITMENTS (Tables)

12 Months Ended

Dec. 31, 2012

LEASE COMMITMENTS

Future net minimum lease payments for noncancelable operating leases

In millions	Amount (a)
2013	$	158
2014	105
2015	106
2016	88
2017	59
Thereafter	460
Total minimum lease payments	$	976

(a) These amounts are net of sublease rentals of $3 million, which are to be received as follows (in millions):  2013—$2 and 2014—$1.

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Consolidated Statements of Stockholders' Equity (USD $) In Millions, unless otherwise specified	Total		Common Stock	Treasury Stock	Additional Paid-in Capital	Retained Earnings	Accumulated Other Comprehensive Income (Loss)	Noncontrolling Interest
Balance at Dec. 31, 2009	$ 29,159		$ 177	$ (4,161)	$ 7,127	$ 26,534	$ (596)	$ 78
Increase (Decrease) in Stockholders' Equity
Net income	4,602					4,530		72
Other comprehensive income (loss), net of tax	72	[1]					72
Dividends on common stock	(1,196)					(1,196)
Issuance of common stock and other, net	64				64
Noncontrolling interest distributions and other	(150)							(150)	[2]
Purchases of treasury stock	(67)			(67)
Balance at Dec. 31, 2010	32,484		177	(4,228)	7,191	29,868	(524)
Increase (Decrease) in Stockholders' Equity
Net income	6,771					6,771
Other comprehensive income (loss), net of tax	41	[1]					41
Dividends on common stock	(1,497)					(1,497)
Issuance of common stock and other, net	95				95
Purchases of treasury stock	(274)			(274)
Balance at Dec. 31, 2011	37,620		177	(4,502)	7,286	35,142	(483)
Increase (Decrease) in Stockholders' Equity
Net income	4,598					4,598
Other comprehensive income (loss), net of tax	(19)	[1]					(19)
Dividends on common stock	(1,750)					(1,750)
Issuance of common stock and other, net	156		1		155
Noncontrolling interest contributions	32							32	[3]
Purchases of treasury stock	(589)			(589)
Balance at Dec. 31, 2012	$ 40,048		$ 178	$ (5,091)	$ 7,441	$ 37,990	$ (502)	$ 32

[1] There were no other comprehensive income (loss) items related to noncontrolling interests in 2012, 2011 and 2010.

[2] On December 31, 2010, Occidental restructured its Colombian operations to take a direct working interest in the related assets.

[3] Reflects contributions from the noncontrolling interest in a pipeline company.

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DERIVATIVES (Tables)

12 Months Ended

Dec. 31, 2012

Derivatives

Cash-flow hedges - pre-tax and after-tax gains and losses recognized in, and reclassified to income from, Accumulated Other Comprehensive Income (in millions)

	After-tax						Pre-Tax
	2012			2011			2012			2011
Beginning Balance - AOCI	$	1		$	(111	)
Unrealized gains recognized in AOCI	16			14			$	25		$	20
(Gains) losses reclassified to income	(24		)	98			$	(38	)	$	154
Ending Balance - AOCI	$	(7	)	$	1

Gross fair value of outstanding derivatives (in millions)

December 31, 2012	Asset Derivatives Balance Sheet Location	Fair Value			Liability Derivatives Balance Sheet Location	Fair Value
Cash-flow hedges (a)
	Other current assets	$	11		Accrued liabilities	$	1
Commodity contracts	Long-term receivables and other assets, net	—			Deferred credits and other liabilities	1
		$	11			$	2
Derivatives not designated as hedging instruments (a)
	Other current assets	$	386		Accrued liabilities	$	479
Commodity contracts	Long-term receivables and other assets, net	22			Deferred credits and other liabilities	16
		408				495
Total gross fair value		419				497
Less: counterparty netting and cash collateral (b)		(301		)		(371		)
Total net fair value of derivatives		$	118			$	126

December 31, 2011	Asset Derivatives Balance Sheet Location	Fair Value			Liability Derivatives Balance Sheet Location	Fair Value
Cash-flow hedges (a)
	Other current assets	$	41		Accrued liabilities	$	5
Commodity contracts	Long-term receivables and other assets, net	3			Deferred credits and other liabilities	—
		$	44			$	5
Derivatives not designated as hedging instruments (a)
	Other current assets	$	835		Accrued liabilities	$	887
Commodity contracts	Long-term receivables and other assets, net	71			Deferred credits and other liabilities	71
		906				958
Total gross fair value		950				963
Less: counterparty netting and cash collateral (c)		(758		)		(782		)
Total net fair value of derivatives		$	192			$	181

(a) Fair values are presented at gross amounts, including when the derivatives are subject to master netting arrangements and qualify for net presentation in the consolidated balance sheet.

(b) As of December 31, 2012, collateral received of $25 million has been netted against derivative assets and collateral paid of $95 million has been netted against derivative liabilities.

(c) As of December 31, 2011, collateral received of $42 million has been netted against derivative assets and collateral paid of $66 million has been netted against derivative liabilities.

Derivatives Not Designated as Hedging Instruments | Commodity Contracts

Derivatives

Schedule of outstanding derivative instruments

	Net Outstanding Position Long / (Short)
Commodity	2012		2011
Oil (million barrels)	(17	)	(9	)
Natural gas (billion cubic feet)	(217	)	(242	)
Precious metals (million troy ounces)	1		3

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INDUSTRY SEGMENTS AND GEOGRAPHIC AREAS (Tables)

12 Months Ended

Dec. 31, 2012

INDUSTRY SEGMENTS AND GEOGRAPHIC AREAS

Industry segment and corporate disclosures

In millions	Oil and Gas			Chemical			Midstream and Marketing			Corporate and Eliminations			Total
YEAR ENDED DECEMBER 31, 2012
Net sales	$	18,906	(a)	$	4,580	(b)	$	1,399	(c)	$	(713	)	$	24,172
Pretax operating profit (loss)	$	7,095	(d)	$	720		$	439		$	(501)	(f,h)	$	7,753
Income taxes	—			—			—			(3,118)		(g,h)	(3,118		)
Discontinued operations, net	—			—			—			(37		)	(37		)
Net income (loss) attributable to common stock	$	7,095		$	720		$	439		$	(3,656	)	$	4,598
Investments in unconsolidated entities	$	113		$	108		$	1,662		$	11		$	1,894
Property, plant and equipment additions, net (i)	$	8,282		$	365		$	1,612		$	91		$	10,350
Depreciation, depletion and amortization	$	3,933		$	345		$	206		$	27		$	4,511
Total assets	$	44,004		$	3,854		$	12,762		$	3,590		$	64,210
YEAR ENDED DECEMBER 31, 2011
Net sales	$	18,419	(a)	$	4,815	(b)	$	1,447	(c)	$	(742	)	$	23,939
Pretax operating profit (loss)	$	10,241	(d)	$	861		$	448		$	(709)	(f,h)	$	10,841	(d)
Income taxes	—			—			—			(4,201)		(g,h)	(4,201		)
Discontinued operations, net	—			—			—			131			131
Net income (loss) attributable to common stock	$	10,241	(d)	$	861		$	448		$	(4,779	)	$	6,771
Investments in unconsolidated entities	$	128		$	121		$	1,812		$	11		$	2,072
Property, plant and equipment additions, net (i)	$	6,192		$	241		$	1,120		$	51		$	7,604
Depreciation, depletion and amortization	$	3,064		$	330		$	173		$	24		$	3,591
Total assets	$	38,967		$	3,754		$	11,962		$	5,361		$	60,044
YEAR ENDED DECEMBER 31, 2010
Net sales	$	14,276	(a)	$	4,016	(b)	$	1,471	(c)	$	(718	)	$	19,045
Pretax operating profit (loss)	$	7,151	(d,e)	$	438		$	472		$	(497)	(f,h)	$	7,564	(d,e)
Income taxes	—			—			—			(2,995)		(g,h)	(2,995		)
Discontinued operations, net	—			—			—			(39		)	(39		)
Net income (loss) attributable to common stock	$	7,151	(d,e)	$	438		$	472		$	(3,531	)	$	4,530	(e)
Investments in unconsolidated entities	$	123		$	135		$	1,770		$	11		$	2,039
Property, plant and equipment additions, net (i)	$	3,211		$	248		$	537		$	38		$	4,034
Depreciation, depletion and amortization	$	2,668		$	321		$	142		$	22		$	3,153
Total assets	$	31,855		$	3,755		$	10,445		$	6,377	(j)	$	52,432

Total product sales for the chemical segment

	Basic Chemicals		Vinyls		Other Chemicals
Year ended December 31, 2012	57	%	40	%	3	%
Year ended December 31, 2011	58	%	39	%	3	%
Year ended December 31, 2010	57	%	40	%	3	%

Total sales for the midstream and marketing segment

	Gas Processing		Power		Marketing, Trading, Transportation and other
Year ended December 31, 2012	59	%	20	%	21	%
Year ended December 31, 2011	64	%	27	%	9	%
Year ended December 31, 2010	52	%	27	%	21	%

Significant items affecting earnings included in the Corporate segment

Benefit (Charge)  (In millions)	2012			2011			2010
CORPORATE
Pre-tax operating profit (loss)
Premium on debt extinguishments	$	—		$	(163	)	$	—
Litigation reserves	(20		)	—			—
	$	(20	)	$	(163	)	$	—
Income taxes
State income tax charge	$	—		$	(33	)	$	—
Foreign tax credit carryforwards	—			—			80
Tax effect of pre-tax adjustments *	636			50			100
	$	636		$	17		$	180

*   Amounts represent the tax effect of all pre-tax adjustments listed, as well as those in footnote (d).

Net sales and property, plant and equipment by geographic areas

In millions

	Net sales (a)						Property, plant and equipment, net
For the years ended December 31,	2012		2011		2010		2012		2011		2010
United States	$	15,359	$	15,040	$	12,151	$	40,786	$	36,283	$	28,571
Foreign
Qatar	3,356		3,432		2,677		2,676		2,735		2,823
Oman	2,578		2,500		1,666		2,353		2,143		1,967
Colombia	1,027		1,054		999		1,041		854		715
Yemen	407		907		766		199		245		347
Bahrain	215		187		100		688		477		222
United Arab Emirates	—		—		—		2,104		971		1
Other Foreign	1,230		819		686		2,217		1,976		1,890
Total Foreign	8,813		8,899		6,894		11,278		9,401		7,965
Total	$	24,172	$	23,939	$	19,045	$	52,064	$	45,684	$	36,536

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

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DERIVATIVES (Details 3) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Outstanding commodity derivatives contracts not designated as hedging instruments
Net Gains (Losses) from derivatives not designated as hedging instruments. (in dollars)	$ 49	$ 94
Oil (in barrels)
Outstanding commodity derivatives contracts not designated as hedging instruments
Net Outstanding Position Long/(Short)	(17,000,000)	(9,000,000)
Natural Gas (in cubic feet)
Outstanding commodity derivatives contracts not designated as hedging instruments
Net Outstanding Position Long/(Short)	(217,000,000)	(242,000,000)
Precious metals (in troy ounces)
Outstanding commodity derivatives contracts not designated as hedging instruments
Net Outstanding Position Long/(Short)	1,000,000	3,000,000

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Consolidated Balance Sheets (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
CURRENT ASSETS
Cash and cash equivalents	$ 1,592	$ 3,781
Trade receivables, net of reserves of $16 in both 2012 and 2011	4,916	5,395
Inventories	1,344	1,069
Other current assets	1,640	1,297
Total current assets	9,492	11,542
INVESTMENTS IN UNCONSOLIDATED ENTITIES	1,894	2,072
PROPERTY, PLANT AND EQUIPMENT
Oil and gas segment	65,417	56,682
Chemical segment	6,054	5,715
Midstream, marketing and other segment	7,191	5,664
Corporate	1,434	1,310
GROSS PROPERTY, PLANT AND EQUIPMENT	80,096	69,371
Accumulated depreciation, depletion and amortization	(28,032)	(23,687)
TOTAL PROPERTY, PLANT AND EQUIPMENT	52,064	45,684
LONG-TERM RECEIVABLES AND OTHER ASSETS, NET	760	746
TOTAL ASSETS	64,210	60,044
CURRENT LIABILITIES
Current maturities of long-term debt	600
Accounts payable	4,708	5,304
Accrued liabilities	1,966	2,533
Domestic and foreign income taxes	16	110
Total current liabilities	7,290	7,947
LONG-TERM DEBT, NET	7,023	5,871
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred domestic and foreign income taxes	6,039	4,846
Other	3,810	3,760
Total deferred credits and other liabilities	9,849	8,606
CONTINGENT LIABILITIES AND COMMITMENTS
STOCKHOLDERS' EQUITY
Common stock, $0.20 par value, authorized 1.1 billion shares, outstanding shares: 2012 - 888,801,436 and 2011 - 886,808,654	178	177
Treasury stock: 2012 - 83,287,187 shares and 2011 - 75,799,573 shares	(5,091)	(4,502)
Additional paid-in capital	7,441	7,286
Retained earnings	37,990	35,142
Accumulated other comprehensive loss	(502)	(483)
Total equity attributable to common stock	40,016	37,620
Noncontrolling interest	32
Total equity	40,048	37,620
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$ 64,210	$ 60,044

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ACQUISITIONS, DISPOSITIONS AND OTHER TRANSACTIONS (Details 4) (USD $) In Millions, unless otherwise specified	1 Months Ended	12 Months Ended
	Feb. 28, 2011	Dec. 31, 2011	Dec. 31, 2010
General Partner of Plains All American Pipeline
Asset acquisitions, dispositions and other transactions
Significant acquisitions (sales)			$ 430
Equity method investment ownership percentage			35.00%
Elk Hills Power
Asset acquisitions, dispositions and other transactions
Significant acquisitions (sales)			175
Equity method investment additional ownership percentage			50.00%
Total ownership percentage			100.00%
China Petrochemical Corporation (Sinopec) | Argentina
Asset acquisitions, dispositions and other transactions
Significant acquisitions (sales)			(2,600)
Pre-tax gain on sale	225
Net revenues of discontinued operations		97	700
Pre-tax income (losses) of discontinued operations		2	(39)
North Dakota Oil Producing and Prospective Properties
Asset acquisitions, dispositions and other transactions
Significant acquisitions (sales)			1,400
Operating, Producing Properties in the Permian, Midcontinent Region and California
Asset acquisitions, dispositions and other transactions
Significant acquisitions (sales)			$ 2,800
Zubair Field development project
Asset acquisitions, dispositions and other transactions
Length of contract (in years)			20

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Consolidated Statements of Comprehensive Income (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
Consolidated Statements of Comprehensive Income
Net income attributable to common stock	$ 4,598		$ 6,771		$ 4,530
Other comprehensive income (loss) items:
Foreign currency translation (losses) gains	(25)		(11)		4
Unrealized gains on derivatives	16	[1]	14	[1]	37	[1]
Pension and postretirement gains (losses)	14	[2]	(60)	[2]	(52)	[2]
Reclassification to income of realized (gains) losses on derivatives	(24)	[3]	98	[3]	83	[3]
Other comprehensive income (loss), net of tax	(19)	[4]	41	[4]	72	[4]
Comprehensive income attributable to common stock	$ 4,579		$ 6,812		$ 4,602

[1] Net of tax of $(9), $(7) and $(20) in 2012, 2011 and 2010, respectively.

[2] Net of tax of $(8), $34 and $30 in 2012, 2011 and 2010, respectively.

[3] Net of tax of $14, $(56) and $(47) in 2012, 2011 and 2010, respectively.

[4] There were no other comprehensive income (loss) items related to noncontrolling interests in 2012, 2011 and 2010.

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STOCKHOLDERS' EQUITY (Details) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Common stock issuances
Balance at the beginning of the year	886,808,654	885,275,000	883,643,000
Issued	1,746,000	1,302,000	967,000
Options exercised and other, net	246,000	232,000	665,000
Balance at the end of the year	888,801,436	886,808,654	885,275,000
TREASURY STOCK
Share repurchase program, authorized shares	95,000,000	95,000,000	95,000,000
Shares purchased under share repurchase program	7,200,000	2,700,000
Share repurchase program, average cost per share of shares repurchased during period	$ 77.98	$ 77.12
Treasury stock, shares	83,287,187	75,799,573	72,480,538
NONREDEEMABLE PREFERRED STOCK
Preferred stock, authorized shares	50,000,000	50,000,000
Preferred stock, par value	$ 1.00	$ 1.00
BASIC EARNINGS PER COMMON SHARE (attributable to common stock)
Income from continuing operations	$ 4,635,000,000	$ 6,640,000,000	$ 4,641,000,000
Less: Income from continuing operations attributable to noncontrolling interest			(72,000,000)
Income from continuing operations attributable to common stock	4,635,000,000	6,640,000,000	4,569,000,000
Discontinued operations, net	(37,000,000)	131,000,000	(39,000,000)
Net income attributable to common stock	4,598,000,000	6,771,000,000	4,530,000,000
Less: Net income allocated to participating securities	(8,000,000)	(11,000,000)	(6,000,000)
Net income attributable to common stock, net of participating securities	4,590,000,000	6,760,000,000	4,524,000,000
Weighted average number of basic shares	809,300,000	812,100,000	812,500,000
Basic EPS (in dollars per share)	$ 5.67	$ 8.32	$ 5.57
DILUTED EARNINGS PER COMMON SHARE (attributable to common stock)
Net income attributable to common stock, net of participating securities	4,590,000,000	6,760,000,000	4,524,000,000
Weighted average number of basic shares	809,300,000	812,100,000	812,500,000
Dilutive effect of potentially dilutive securities (in shares)	700,000	800,000	1,300,000
Total diluted weighted average common shares	810,000,000	812,900,000	813,800,000
Diluted EPS (in dollars per share)	$ 5.67	$ 8.32	$ 5.56
After-tax charges for the impairment of domestic gas assets and related items	1,100,000,000
ACCUMULATED OTHER COMPREHENSIVE LOSS
Foreign currency translation adjustments	(34,000,000)	(9,000,000)
Unrealized gains (losses) on derivatives	(7,000,000)	1,000,000	(111,000,000)
Pension and post-retirement adjustments	(461,000,000)	(475,000,000)
Accumulated other comprehensive loss	$ (502,000,000)	$ (483,000,000)

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STOCKHOLDERS' EQUITY (Tables)

12 Months Ended

Dec. 31, 2012

STOCKHOLDERS' EQUITY

Analysis of common stock issuances

Shares in thousands	Common Stock
Balance, December 31, 2009	883,643
Issued	967
Options exercised and other, net	665
Balance, December 31, 2010	885,275
Issued	1,302
Options exercised and other, net	232
Balance, December 31, 2011	886,809
Issued	1,746
Options exercised and other, net	246
Balance, December 31, 2012	888,801

Calculation of basic and diluted EPS

In millions, except per-share amounts	2012			2011			2010
Basic EPS
Income from continuing operations	$	4,635	(a)	$	6,640		$	4,641
Less: Income from continuing operations attributable to noncontrolling interest	—			—			(72		)
Income from continuing operations attributable to common stock	4,635			6,640			4,569
Discontinued operations, net	(37		)	131			(39		)
Net income attributable to common stock	4,598			6,771			4,530
Less: Net income allocated to participating securities	(8		)	(11		)	(6		)
Net income attributable to common stock, net of participating securities	$	4,590		$	6,760		$	4,524
Weighted average number of basic shares	809.3			812.1			812.5
Basic EPS	$	5.67		$	8.32		$	5.57
Diluted EPS
Net income attributable to common stock, net of participating securities	$	4,590		$	6,760		$	4,524
Weighted average number of basic shares	809.3			812.1			812.5
Dilutive effect of potentially dilutive securities	0.7			0.8			1.3
Total diluted weighted average common shares	810.0			812.9			813.8
Diluted EPS	$	5.67		$	8.32		$	5.56

(a) Includes after-tax charges of $1.1 billion for the impairment of domestic gas assets and related items.

Components of accumulated other comprehensive loss

Balance at December 31, (in millions)	2012			2011
Foreign currency translation adjustments	$	(34	)	$	(9	)
Unrealized gains (losses) on derivatives	(7		)	1
Pension and post-retirement adjustments (a)	(461		)	(475		)
Total	$	(502	)	$	(483	)

(a) See Note 13 for further information.

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INDUSTRY SEGMENTS AND GEOGRAPHIC AREAS (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012 segment	Dec. 31, 2011 segment	Dec. 31, 2010 segment
INDUSTRY SEGMENTS AND GEOGRAPHIC AREAS
Number of reportable segments	3	3	3
Segment Information
Net sales	$ 24,172	$ 23,939	$ 19,045
Pretax operating profit (loss)	7,753	10,841	7,564
Income taxes	(3,118)	(4,201)	(2,995)
Discontinued operations, net	(37)	131	(39)
Net income (loss) attributable to common stock	4,598	6,771	4,530
Investments in unconsolidated entities	1,894	2,072	2,039
Property, plant and equipment additions, net	10,350	7,604	4,034
Depreciation, depletion and amortization	4,511	3,591	3,153
Total assets	64,210	60,044	52,432
Asset impairments and related items	1,751		275
Net income attributable to noncontrolling interest			72
Total Foreign
Segment Information
Net sales	8,813	8,899	6,894
Colombia
Segment Information
Net sales	1,027	1,054	999
Colombian net worth tax		29
Pre-tax gain for sale of interest in Colombian pipeline		22
Libya
Segment Information
Capitalized and suspended exploration costs written off		35
Oil and Gas
Segment Information
Net sales	18,906	18,419	14,276
Pretax operating profit (loss)	7,095	10,241	7,151
Net income (loss) attributable to common stock	7,095	10,241	7,151
Investments in unconsolidated entities	113	128	123
Property, plant and equipment additions, net	8,282	6,192	3,211
Depreciation, depletion and amortization	3,933	3,064	2,668
Total assets	44,004	38,967	31,855
Asset impairments and related items	1,731		275
Net income attributable to noncontrolling interest			72
Oil and Gas | Oil
Segment Information
Product revenue to net sales (as a percent)	90.00%	87.00%	86.00%
Chemical
Segment Information
Net sales	4,580	4,815	4,016
Pretax operating profit (loss)	720	861	438
Net income (loss) attributable to common stock	720	861	438
Investments in unconsolidated entities	108	121	135
Property, plant and equipment additions, net	365	241	248
Depreciation, depletion and amortization	345	330	321
Total assets	3,854	3,754	3,755
Chemical | Basic Chemicals
Segment Information
Product revenue to net sales (as a percent)	57.00%	58.00%	57.00%
Chemical | Vinyls
Segment Information
Product revenue to net sales (as a percent)	40.00%	39.00%	40.00%
Chemical | Other Chemicals
Segment Information
Product revenue to net sales (as a percent)	3.00%	3.00%	3.00%
Midstream and Marketing
Segment Information
Net sales	1,399	1,447	1,471
Pretax operating profit (loss)	439	448	472
Net income (loss) attributable to common stock	439	448	472
Investments in unconsolidated entities	1,662	1,812	1,770
Property, plant and equipment additions, net	1,612	1,120	537
Depreciation, depletion and amortization	206	173	142
Total assets	12,762	11,962	10,445
Midstream and Marketing | Gas Processing
Segment Information
Sales revenues for businesses as a percentage of total sales revenues	59.00%	64.00%	52.00%
Midstream and Marketing | Power
Segment Information
Sales revenues for businesses as a percentage of total sales revenues	20.00%	27.00%	27.00%
Midstream and Marketing | Marketing, Trading, Transportation and other
Segment Information
Sales revenues for businesses as a percentage of total sales revenues	21.00%	9.00%	21.00%
Corporate and Eliminations
Segment Information
Net sales	(713)	(742)	(718)
Pretax operating profit (loss)	(501)	(709)	(497)
Income taxes	(3,118)	(4,201)	(2,995)
Discontinued operations, net	(37)	131	(39)
Net income (loss) attributable to common stock	(3,656)	(4,779)	(3,531)
Investments in unconsolidated entities	11	11	11
Property, plant and equipment additions, net	91	51	38
Depreciation, depletion and amortization	27	24	22
Total assets	$ 3,590	$ 5,361	$ 6,377

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RETIREMENT AND POSTRETIREMENT BENEFIT PLANS

12 Months Ended

Dec. 31, 2012

RETIREMENT AND POSTRETIREMENT BENEFIT PLANS

RETIREMENT AND POSTRETIREMENT BENEFIT PLANS

NOTE 13 RETIREMENT AND POSTRETIREMENT BENEFIT PLANS

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

DEFINED CONTRIBUTION PLANS

All domestic employees and certain foreign national employees are eligible to participate in one or more of the defined contribution retirement or savings plans that provide for periodic contributions by Occidental based on plan-specific criteria, such as base pay, age, level and employee contributions.  Certain salaried employees participate in a supplemental retirement plan that restores benefits lost due to governmental limitations on qualified retirement benefits.  The accrued liabilities for the supplemental retirement plan were $145 million and $126 million as of December 31, 2012 and 2011, respectively, and Occidental expensed $137 million in 2012, $110 million in 2011 and $101 million in 2010 under the provisions of these defined contribution and supplemental retirement plans.

DEFINED BENEFIT PLANS

Participation in defined benefit plans is limited and approximately 1,000 domestic and 1,600 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.

POSTRETIREMENT AND OTHER BENEFIT PLANS

Occidental provides medical and dental benefits and life insurance coverage for certain active, retired and disabled employees and their eligible dependents.  Occidental generally funds the benefits as they are paid during the year.  These  benefit costs, including the postretirement costs, were approximately $218 million in 2012, $194 million in 2011 and $180 million in 2010.

OBLIGATIONS AND FUNDED STATUS

The following tables show the amounts recognized in the consolidated balance sheets of Occidental related to its pension and postretirement benefit plans and their funding status, obligations and plan asset fair values (in millions):

	Pension Benefits						Postretirement Benefits
As of December 31,	2012			2011			2012			2011
Amounts recognized in the consolidated balance sheet:
Other assets	$	24		$	24		$	—		$	—
Accrued liabilities	(4		)	(5		)	(59		)	(47		)
Deferred credits and other liabilities — other	(136		)	(136		)	(1,068		)	(1,045		)
	$	(116	)	$	(117	)	$	(1,127	)	$	(1,092	)
AOCI included the following after-tax balances:
Net loss	$	134		$	146		$	324		$	331
Prior service cost	1			2			2			2
	$	135		$	148		$	326		$	333
For the years ended December 31,
Changes in benefit obligation:
Benefit obligation — beginning of year	$	592		$	615		$	1,092		$	991
Service cost — benefits earned during the period	13			12			25			22
Interest cost on projected benefit obligation	27			29			42			45
Actuarial loss	46			49			26			81
Foreign currency exchange rate (gain) loss	2			(5		)	—			—
Benefits paid	(57		)	(51		)	(58		)	(47		)
Settlements	(8		)	(57		)	—			—
Benefit obligation — end of year	$	615		$	592		$	1,127		$	1,092
Changes in plan assets:
Fair value of plan assets — beginning of year	$	475		$	495		$	—		$	—
Actual return on plan assets	61			13			—			—
Foreign currency exchange rate gain (loss)	(3		)	(3		)	—			—
Employer contributions	31			78			—			—
Benefits paid	(57		)	(51		)	—			—
Settlements	(8		)	(57		)	—			—
Fair value of plan assets — end of year	$	499		$	475		$	—		$	—
Unfunded status:	$	(116	)	$	(117	)	$	(1,127	)	$	(1,092	)

The following table sets forth details of the obligations and assets of Occidental’s defined benefit pension plans (in millions):

	Accumulated Benefit Obligation in Excess of Plan Assets				Plan Assets in Excess of Accumulated Benefit Obligation
As of December 31, (in millions)	2012		2011		2012		2011
Projected Benefit Obligation	$	305	$	361	$	310	$	231
Accumulated Benefit Obligation	$	278	$	334	$	305	$	227
Fair Value of Plan Assets	$	171	$	226	$	328	$	249

Occidental does not expect any plan assets to be returned during 2013.

COMPONENTS OF NET PERIODIC BENEFIT COST

The following table sets forth the components of net periodic benefit costs (in millions):

	Pension Benefits									Postretirement Benefits
For the years ended December 31, (in millions)	2012			2011			2010			2012		2011		2010
Net periodic benefit costs:
Service cost — benefits earned during the period	$	13		$	12		$	16		$	25	$	22	$	19
Interest cost on benefit obligation	27			29			30			42		45		44
Expected return on plan assets	(31		)	(33		)	(31		)	—		—		—
Recognized actuarial loss	19			13			15			37		31		27
Other costs and adjustments	17			—			10			1		1		1
Net periodic benefit cost	$	45		$	21		$	40		$	105	$	99	$	91

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 $17 million and $0, respectively.  The estimated net loss and prior service cost for the defined benefit postretirement plans that will be amortized from AOCI into net periodic benefit cost over the next fiscal year are $37 million and $1 million, respectively.

ADDITIONAL INFORMATION

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
For the years ended December 31,	2012		2011		2012		2011
Benefit Obligation Assumptions:
Discount rate	3.59	%	4.12	%	3.89	%	4.12	%
Rate of compensation increase	4.00	%	4.00	%	—		—
Net Periodic Benefit Cost Assumptions:
Discount rate	4.12	%	4.74	%	4.12	%	4.74	%
Assumed long term rate of return on assets	6.50	%	6.50	%	—		—
Rate of compensation increase	4.00	%	4.00	%	—		—

For domestic pension plans and postretirement benefit plans, Occidental based the discount rate on the Aon/Hewitt AA-AAA Universe yield curve in 2012 and 2011.  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.  Occidental considers historical returns and correlation of equities and fixed-income securities and current market factors such as inflation and interest rates.

For pension plans outside the United States, Occidental based its discount rate on rates indicative of government or investment grade corporate debt in the applicable country, taking into account hyperinflationary environments when necessary.  The discount rates used for the foreign pension plans ranged from 1.5 percent to 10.0 percent at both December 31, 2012 and 2011.  The average rate of increase in future compensation levels ranged from 1.5 percent to 10.0 percent in 2012, depending on local economic conditions.  The expected long-term rate of return on plan assets was 6.5 percent and 5.8 percent in excess of local inflation in 2012 and 2011, respectively.

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 healthcare cost trend rates projected at an assumed U.S. Consumer Price Index (CPI) increase of 2.39 percent and 2.04 percent as of December 31, 2012 and 2011, respectively.  Since 1993, participants other than certain union employees have paid for all medical cost increases in excess of increases in the CPI.  For those union employees, Occidental projected that healthcare cost trend rates would decrease 0.5 percent per year from 8.5 percent in 2012 until they reach 6.0 percent in 2017, and remain at 6.0 percent thereafter.  A 1-percent increase or a 1-percent decrease in these assumed healthcare cost trend rates would result in an increase of $44 million or a reduction of $37 million, respectively, in the postretirement benefit obligation as of December 31, 2012.  The annual service and interest 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 assets and liabilities.

FAIR VALUE OF PENSION PLAN ASSETS

Occidental employs a total return investment approach that uses a diversified blend of equity and fixed-income investments to optimize 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 investments across the spectrum of asset classes.  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 with the goals of enhancing long-term returns and improving portfolio diversification.  The target allocation of plan assets is 60 percent equity securities and 40 percent debt securities.  Investment performance is measured and monitored on an ongoing basis through quarterly investment portfolio and manager guideline compliance reviews, annual liability measurements and periodic studies.

The fair values of Occidental’s pension plan assets by asset category are as follows (in millions):

	Fair Value Measurements at December 31, 2012 Using
Description	Level 1		Level 2		Level 3		Total
Asset Class:
U.S. government securities	$	24	$	—	$	—	$	24
Corporate bonds (a)	—		83		—		83
Common/collective trusts (b)	—		11		—		11
Mutual funds:
Bond funds	84		—		—		84
Blend funds	106		—		—		106
Value and growth funds	5		—		—		5
Common and preferred stocks (c)	146		—		—		146
Other	—		35		11		46
Total pension plan assets (d)	$	365	$	129	$	11	$	505

	Fair Value Measurements at December 31, 2011 Using
Description	Level 1		Level 2		Level 3		Total
Asset Class:
U.S. government securities	$	22	$	—	$	—	$	22
Corporate bonds (a)	—		83		—		83
Common/collective trusts (b)	—		14		—		14
Mutual funds:
Bond funds	84		—		—		84
Blend funds	97		—		—		97
Value and growth funds	5		—		—		5
Common and preferred stocks (c)	131		—		—		131
Other	—		34		12		46
Total pension plan assets (d)	$	339	$	131	$	12	$	482

(a) This category represents investment grade bonds of U.S. and non-U.S. issuers from diverse industries.

(b) This category includes investment funds that primarily invest in U.S. and non-U.S. common stocks and fixed-income securities.

(c) This category represents direct investments in common and preferred stocks from diverse U.S. and non-U.S. industries.

(d) Amounts exclude net payables of approximately $6 million and $7 million as of December 31, 2012 and 2011, respectively.

The activity during the years ended December 31, 2012 and 2011 for the assets using Level 3 fair value measurements was insignificant.

Occidental expects to contribute $5 million in cash to its defined benefit pension plans during 2013.

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
2013	$	40	$	50
2014	$	44	$	51
2015	$	41	$	52
2016	$	46	$	53
2017	$	42	$	54
2018 — 2022	$	230	$	294

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STOCK-BASED INCENTIVE PLANS (Tables)

12 Months Ended

Dec. 31, 2012

STOCK-BASED INCENTIVE PLANS

Summary of certain stock-based incentive amounts

For the years ended December 31, (in millions)	2012		2011		2010
Compensation expense	$	78	$	110	$	136
Income tax benefit recognized in the income statement	$	29	$	40	$	50
Intrinsic value of options and stock-settled SARs exercised	$	18	$	21	$	74
Cash paid (a)	$	83	$	124	$	97
Fair value of RSUs and TSRIs vested during the year (b)	$	28	$	53	$	19

(a) Includes cash paid under the cash-settled portion of the SARs, RSUs and TSRIs.

(b) As measured on the vesting date for the stock-settled portion of the RSUs and TSRIs.

Summary of changes in Occidental's unvested cash- and stock- settled RSUs

	Cash-Settled			Stock-Settled
	RSUs (000’s)		Weighted-Average Grant-Date Fair Value	RSUs (000’s)		Weighted-Average Grant-Date Fair Value
Unvested at January 1	1,272		$90.50	568		$93.14
Granted	729		$84.38	824		$84.81
Vested	(621	)	$83.61	(9	)	$88.21
Forfeitures	(48	)	$92.90	(8	)	$84.57
Unvested at December 31	1,332		$90.27	1,375		$88.23

Summary of Option and SAR transactions

	Cash-Settled							Stock-Settled
	SARs (000’s)		Weighted- Average Exercise Price		Weighted- Average Remaining Contractual Term (yrs)	Aggregate Intrinsic Value (000’s)		SARs & Options (000’s)		Weighted- Average Exercise Price		Weighted- Average Remaining Contractual Term (yrs)	Aggregate Intrinsic Value (000’s)
Beginning balance, January 1	564		$	24.66				782		$	26.34
Exercised	(70	)	$	24.66				(245	)	$	14.22
Ending balance, December 31	494		$	24.66	1.5	$	25,639	537		$	31.88	2.0	$	24,008
Exercisable at December 31	494		$	24.66	1.5	$	25,639	537		$	31.88	2.0	$	24,008

Grant-date assumptions used in the Monte Carlo simulation models for the estimated payout level of TSRIs

	TSRIs
Year Granted	2012			2011			2010
Assumptions used:
Risk-free interest rate	0.4		%	0.6		%	0.6		%
Dividend yield	2.6		%	1.8		%	1.8		%
Volatility factor	34		%	33		%	32		%
Expected life (years)	3			3			3
Grant-date fair value of underlying Occidental common stock	$	84.57		$	102.97		$	84.29

Summary of Occidental's unvested TSRIs

	TSRIs
	Awards (000’s)		Weighted-Average Grant-Date Fair Value of Occidental Stock
Unvested at January 1 (a)	1,865			$	78.67
Granted (a)	453			$	84.57
Vested (b)	(388	)		$	77.00
Forfeitures	—			$	—
Unvested at December 31 (a)	1,930			$	80.39

(a) Unvested awards and award grants are presented at the target or mid-point payouts.

(b) The payout at vesting was 150 percent of the target for TSRIs.

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FAIR VALUE MEASUREMENTS

12 Months Ended

Dec. 31, 2012

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS

NOTE 15 FAIR VALUE MEASUREMENTS

FAIR VALUES — RECURRING

The following tables provide fair value measurement information for assets and liabilities that are measured on a recurring basis as of December 31, 2012 and 2011 (in millions):

	Fair Value Measurements at December 31, 2012 Using						Netting and			Total
Description	Level 1		Level 2		Level 3		Collateral (a)			Fair Value
Assets:
Commodity derivatives	$	107	$	312	$	—	$	(301	)	$	118
Liabilities:
Commodity derivatives	$	99	$	398	$	—	$	(371	)	$	126

	Fair Value Measurements at December 31, 2011 Using						Netting and			Total
Description	Level 1		Level 2		Level 3		Collateral (a)			Fair Value
Assets:
Commodity derivatives	$	310	$	640	$	—	$	(758	)	$	192
Liabilities:
Commodity derivatives	$	311	$	652	$	—	$	(782	)	$	181

(a) Represents the impact of netting assets, liabilities and collateral when a legal right of offset exists.

FAIR VALUES — NONRECURRING

Occidental performed impairment tests with respect to its proved and unproved properties due to the negative revisions to certain of its natural gas reserves and the continued deterioration of natural gas prices.  The impairment tests, including the fair value estimation, incorporate a number of assumptions involving expectations of future cash flows.  These assumptions include estimates of future product prices, which Occidental bases on forward price curves and, where applicable, contractual prices, estimates of oil and gas reserves, estimates of future expected operating and development costs and appropriate discount rates.

In 2012, Occidental recorded pre-tax impairment charges of $1.7 billion, almost all of which were for certain assets in Midcontinent, over 90 percent of which were related to natural gas properties, which were acquired more than four years ago on average.  These properties were impacted by persistently low natural gas prices in the United States changing management’s development plans and negative reserve revisions due to recent well performance.  In 2010, Occidental recorded a pre-tax impairment charge of $275 million, predominantly of gas properties in the Rocky Mountain region.  Occidental used the income approach to measure the fair value of these properties, using inputs categorized as Level 3 in the fair value hierarchy.

FINANCIAL INSTRUMENTS FAIR VALUE

The carrying amounts of cash and cash equivalents and other on-balance-sheet financial instruments, other than fixed-rate debt, approximate fair value.  The cost, if any, to terminate off-balance-sheet financial instruments is not significant.

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Consolidated Statements of Comprehensive Income (Parenthetical) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Consolidated Statements of Comprehensive Income
Unrealized gains on derivatives, tax	$ (9)	$ (7)	$ (20)
Pension and postretirement gains (losses), tax	(8)	34	30
Reclassification to income of realized (gains) losses on derivatives, tax	$ 14	$ (56)	$ (47)

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Consolidated Balance Sheets (Parenthetical) (USD $) In Millions, except Share data, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Consolidated Balance Sheets
Trade receivables, reserves (in dollars)	$ 16	$ 16
Common stock, par value (in dollars per share)	$ 0.20	$ 0.20
Common stock, authorized shares	1,100,000,000	1,100,000,000
Common stock, outstanding shares	888,801,436	886,808,654
Treasury stock, shares	83,287,187	75,799,573

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ENVIRONMENTAL LIABILITIES AND EXPENDITURES

12 Months Ended

Dec. 31, 2012

ENVIRONMENTAL LIABILITIES AND EXPENDITURES

ENVIRONMENTAL LIABILITIES AND EXPENDITURES

NOTE 8 ENVIRONMENTAL LIABILITIES AND EXPENDITURES

Occidental’s operations are subject to stringent federal, state, local and foreign laws and regulations related to improving or maintaining environmental quality.

ENVIRONMENTAL REMEDIATION

The laws that require or address environmental remediation, including CERCLA and similar federal, state, local and foreign laws, may apply retroactively and regardless of fault, the legality of the original activities or the current ownership or control of sites.  OPC or certain of its subsidiaries participate in or actively monitor a range of remedial activities and government or private proceedings under these laws with respect to alleged past practices at operating, closed and third-party sites.  Remedial activities may include one or more of the following:  investigation involving sampling, modeling, risk assessment or monitoring; cleanup measures including removal, treatment or disposal; or operation and maintenance of remedial systems.  The environmental proceedings seek funding or performance of remediation and, in some cases, compensation for alleged property damage, punitive damages, civil penalties, injunctive relief and government oversight costs.

As of December 31, 2012, Occidental participated in or monitored remedial activities or proceedings at 161 sites.  The following table presents Occidental’s environmental remediation reserves as of December 31, 2012, 2011 and 2010, the current portion of which is included in accrued liabilities ($80 million in 2012, $79 million in 2011 and $79 million in 2010) and the remainder in deferred credits and other liabilities — other ($264 million in 2012, $281 million in 2011 and $287 million in 2010).  The reserves are grouped as environmental remediation sites listed or proposed for listing by the U.S. Environmental Protection Agency on the CERCLA National Priorities List (NPL sites) and three categories of non-NPL sites — third-party sites, Occidental-operated sites and closed or non-operated Occidental sites.

$ amounts in millions	2012			2011			2010
	Number of Sites	Reserve Balance		Number of Sites	Reserve Balance		Number of Sites	Reserve Balance
NPL sites	35	$	54	36	$	63	38	$	56
Third-party sites	75	84		73	88		83	91
Occidental-operated sites	22	123		22	120		20	122
Closed or non-operated Occidental sites	29	83		29	89		29	97
Total	161	$	344	160	$	360	170	$	366

As of December 31, 2012, Occidental’s environmental reserves exceeded $10 million each at 12 of the 161 sites described above, and 112 of the sites had reserves from $0 to $1 million each.

As of December 31, 2012, two landfills in western New York owned by Occidental accounted for 73 percent of its reserves associated with NPL sites.  In connection with a 1986 acquisition, Maxus Energy Corporation has retained the liability and indemnified Occidental for 14 of the remaining NPL sites.

As of December 31, 2012, Maxus has also retained the liability and indemnified Occidental for 8 of the 75 third-party sites.  Two of the remaining 67 third-party sites — a former copper mining and smelting operation in Tennessee and a containment and removal project in Tennessee — accounted for 43 percent of Occidental’s reserves associated with these sites.

Five sites — chemical plants in Kansas, Louisiana, Texas and New York and a group of oil and gas properties in the southwestern United States — accounted for 70 percent of the reserves associated with the Occidental-operated sites.

Three other sites — former chemical plants in Tennessee and Delaware and a closed coal mine in Pennsylvania — accounted for 55 percent of the reserves associated with closed or non-operated Occidental sites.

Environmental reserves vary over time depending on factors such as acquisitions or dispositions, identification of additional sites and remedy selection and implementation.  The following table presents environmental reserve activity for the past three years:

In millions	2012			2011			2010
Balance — Beginning of Year	$	360		$	366		$	403
Remediation expenses and interest accretion	56			53			26
Changes from acquisitions/dispositions	—			14			3
Payments	(72		)	(73		)	(66		)
Balance — End of Year	$	344		$	360		$	366

Based on current estimates, Occidental expects to expend funds corresponding to approximately half of the current environmental reserves at the sites described above over the next four years and the balance at these sites over the subsequent 10 or more years.  Occidental believes its range of reasonably possible additional losses beyond those liabilities recorded for environmental remediation at these sites could be up to $375 million.

ENVIRONMENTAL COSTS

Occidental’s environmental costs, some of which include estimates, are presented below for each segment for each of the years ended December 31:

In millions	2012		2011		2010
Operating Expenses
Oil and Gas	$	160	$	158	$	108
Chemical	70		68		72
Midstream and Marketing	20		21		13
	$	250	$	247	$	193
Capital Expenditures
Oil and Gas	$	122	$	110	$	72
Chemical	18		15		19
Midstream and Marketing	12		15		13
	$	152	$	140	$	104
Remediation Expenses
Corporate	$	56	$	52	$	25

Operating expenses are incurred on a continual basis.  Capital expenditures relate to longer-lived improvements in currently operating properties.  Remediation expenses relate to existing conditions from past operations.

XML

Document and Entity Information (USD $) In Billions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Jan. 31, 2013	Jun. 30, 2012
Document and Entity Information
Entity Registrant Name	OCCIDENTAL PETROLEUM CORP /DE/
Entity Central Index Key	0000797468
Document Type	10-K
Document Period End Date	Dec. 31, 2012
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$ 68.1
Entity Common Stock, Shares Outstanding		805,515,153
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	FY

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LAWSUITS, CLAIMS, COMMITMENTS AND CONTINGENCIES

12 Months Ended

Dec. 31, 2012

LAWSUITS, CLAIMS, COMMITMENTS AND CONTINGENCIES

LAWSUITS, CLAIMS, COMMITMENTS AND CONTINGENCIES

NOTE 9 LAWSUITS, CLAIMS, COMMITMENTS AND CONTINGENCIES

OPC or certain of its subsidiaries are involved, in the normal course of business, in lawsuits, claims and other legal proceedings that seek, among other things, compensation for alleged personal injury, breach of contract, property damage or other losses, punitive damages, civil penalties, or injunctive or declaratory relief.  OPC or certain of its subsidiaries also are involved 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, civil penalties and injunctive relief.  Usually OPC or such subsidiaries are among many companies in these environmental proceedings and have to date been successful in sharing response costs with other financially sound companies.  Further, some lawsuits, claims and legal proceedings involve acquired assets with respect to which third-parties retain liability or indemnify Occidental for conditions that existed prior to purchase.

Occidental accrues reserves for currently outstanding lawsuits, claims and proceedings when it is probable that a liability has been incurred and the liability can be reasonably estimated.  Occidental has disclosed its reserve balances for environmental matters.  Reserve balances for other matters as of December 31, 2012 and 2011, were not material to Occidental’s consolidated balance sheets.  Occidental also evaluates the amount of reasonably possible losses that it could incur as a result of the matters mentioned above.  Occidental has disclosed its range of reasonably possible additional losses for sites where it is a participant in environmental remediation.  Occidental believes that other reasonably possible losses that it could incur in excess of reserves accrued on the balance sheet would not be material to its consolidated financial position or results of operations.

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.  Although taxable years through 2009 for United States federal income tax purposes have been audited by the United States Internal Revenue Service (IRS) pursuant to its Compliance Assurance Program, subsequent taxable years are currently under review.  Additionally, in December 2012, Occidental filed United States federal refund claims for tax years 2008 and 2009 which are subject to IRS review.  Taxable years from 2000 through the current year remain subject to examination by foreign and state government tax authorities in certain jurisdictions.  In certain of these jurisdictions, tax authorities are in various stages of auditing Occidental’s income taxes.  During the course of tax audits, disputes have arisen and other disputes may arise as to facts and matters of law.  Occidental believes that the resolution of outstanding tax matters would not have a material adverse effect on its consolidated financial position or results of operations.

OPC, its subsidiaries or both have entered into agreements providing for future payments to secure terminal and pipeline capacity, drilling rigs and services, electrical power, steam and certain chemical raw materials.  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.  At December 31, 2012, total purchase obligations were $8.7 billion, which included approximately $2.7 billion, $1.4 billion, $700 million, $500 million and $400 million that will be paid in 2013, 2014, 2015, 2016 and 2017, respectively.  Included in the purchase obligations are commitments for major fixed and determinable capital expenditures during 2013 and thereafter, which were approximately $2.2 billion.

OPC, its subsidiaries or both have indemnified various parties against specified liabilities 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, 2012, Occidental is not aware of circumstances that it believes would reasonably be expected to lead to indemnity claims that would result in payments materially in excess of reserves.

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Consolidated Statements of Income (USD $) In Millions, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
REVENUES AND OTHER INCOME
Net sales	$ 24,172	$ 23,939	$ 19,045
Interest, dividends and other income	81	180	112
TOTAL REVENUES AND OTHER INCOME	24,253	24,119	19,157
COSTS AND OTHER DEDUCTIONS
Cost of sales (excludes depreciation, depletion and amortization of $4,504 in 2012, $3,584 in 2011 and $3,145 in 2010)	7,844	7,385	6,112
Selling, general and administrative and other operating expenses	1,602	1,523	1,396
Depreciation, depletion and amortization	4,511	3,591	3,153
Asset impairments and related items	1,751		275
Taxes other than on income	680	605	484
Exploration expense	345	258	262
Interest and debt expense, net	130	298	116
TOTAL COSTS AND OTHER DEDUCTIONS	16,863	13,660	11,798
INCOME BEFORE INCOME TAXES AND OTHER ITEMS	7,390	10,459	7,359
Provision for domestic and foreign income taxes	(3,118)	(4,201)	(2,995)
Income from equity investments	363	382	277
INCOME FROM CONTINUING OPERATIONS	4,635	6,640	4,641
Discontinued operations, net	(37)	131	(39)
NET INCOME	4,598	6,771	4,602
Less: Net income attributable to noncontrolling interest			(72)
NET INCOME ATTRIBUTABLE TO COMMON STOCK	$ 4,598	$ 6,771	$ 4,530
BASIC EARNINGS PER COMMON SHARE (attributable to common stock)
Income from continuing operations (in dollars per share)	$ 5.72	$ 8.16	$ 5.62
Discontinued operations, net (in dollars per share)	$ (0.05)	$ 0.16	$ (0.05)
BASIC EARNINGS PER COMMON SHARE (in dollars per share)	$ 5.67	$ 8.32	$ 5.57
DILUTED EARNINGS PER COMMON SHARE (attributable to common stock)
Income from continuing operations (in dollars per share)	$ 5.71	$ 8.16	$ 5.61
Discontinued operations, net (in dollars per share)	$ (0.04)	$ 0.16	$ (0.05)
DILUTED EARNINGS PER COMMON SHARE (in dollars per share)	$ 5.67	$ 8.32	$ 5.56
DIVIDENDS PER COMMON SHARE (in dollars per share)	$ 2.16	$ 1.84	$ 1.47

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ACCOUNTING AND DISCLOSURE CHANGES

12 Months Ended

Dec. 31, 2012

ACCOUNTING AND DISCLOSURE CHANGES

ACCOUNTING AND DISCLOSURE CHANGES

NOTE 3 ACCOUNTING AND DISCLOSURE CHANGES

RECENTLY ADOPTED ACCOUNTING AND DISCLOSURE CHANGES

Fair Value Measurements

Beginning in the quarter ended March 31, 2012, Occidental enhanced its fair value measurement application and disclosures as a result of adopting new requirements issued by the Financial Accounting Standards Board in May 2011.  The new rules include revisions to the standards for the use of fair value measurements and additional disclosures for: (i) all transfers between Level 1 and Level 2 of the fair value hierarchy; (ii) Level 3 measurements; and (iii) hierarchy classifications used for assets and liabilities whose fair value is disclosed only in the footnotes.  The new rules did not have a material impact on Occidental.

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ACQUISITIONS, DISPOSITIONS AND OTHER TRANSACTIONS

12 Months Ended

Dec. 31, 2012

ACQUISITIONS, DISPOSITIONS AND OTHER TRANSACTIONS

ACQUISITIONS, DISPOSITIONS AND OTHER TRANSACTIONS

NOTE 2 ACQUISITIONS, DISPOSITIONS AND OTHER TRANSACTIONS

2012

During the year ended December 31, 2012, Occidental paid approximately $2.3 billion for domestic oil and gas properties in the Permian Basin, Williston Basin, South Texas and California.

In November 2012, Occidental and Magellan Midstream Partners, L.P. (Magellan) formed BridgeTex Pipeline Company, LLC (BridgeTex) and are proceeding with the construction of the BridgeTex Pipeline, which is expected to begin service in mid-2014.  The approximately 450-mile-long pipeline will be capable of transporting approximately 300,000 barrels per day of crude oil between the Permian region (Colorado City, TX) and the Gulf Coast refinery markets.  The BridgeTex Pipeline project also includes construction of approximately 2.6 million barrels of oil storage in aggregate.

Occidental owns a 50% interest in BridgeTex and the remaining 50% interest is owned by Magellan, which also serves as the operator.  BridgeTex was determined to be a variable interest entity because of the difference between Occidental’s economic interests and its decision-making rights. Occidental is the primary beneficiary and consequently consolidates BridgeTex.  At December 31, 2012, BridgeTex held approximately $50 million of money market mutual funds, classified as cash equivalents, which approximates fair value using Level 1  inputs.  BridgeTex’s assets cannot be used for the obligations of, nor do BridgeTex’s creditors have recourse to, OPC or its other subsidiaries.

2011

During the year ended December 31, 2011, Occidental acquired producing properties in South Texas for approximately $1.8 billion.  Occidental also acquired approximately $2.6 billion of other domestic oil and gas assets, which included properties in California, as well as the Permian and Williston Basins.

In the first quarter of 2011, Occidental completed the sale of its Argentine oil and gas operations.

Internationally, in the first quarter of 2011, Occidental acquired a 40-percent participating interest in the Al Hosn gas  project in Abu Dhabi, joining with the Abu Dhabi National Oil Company in a 30-year joint venture agreement.  The project is operated by Abu Dhabi Gas Development Company Limited.  In May 2011, Occidental paid approximately $500 million for its share of pre-acquisition development expenditures.

In early 2011, Occidental ceased exploration activity and its participation in production operations in Libya due to civil unrest in the country and United States sanctions.  As a result, Occidental wrote off the entire amount of the capitalized and suspended exploration costs incurred to date, including lease acquisition costs, of approximately $35 million in the first quarter of 2011.  The United States government lifted its sanctions in September 2011 and Occidental resumed its participation in the producing operations at that time.

2010

In December 2010, Occidental acquired oil producing and prospective properties in North Dakota for approximately $1.4 billion in cash.  In 2010, Occidental also acquired various domestic oil and gas interests, in operated, producing and non-producing properties in the Permian Basin, Midcontinent region and California, for approximately $2.8 billion.

In December 2010, Occidental executed an agreement with a subsidiary of China Petrochemical Corporation (Sinopec) to sell its Argentine oil and gas operations for after-tax proceeds of approximately $2.6 billion.  Occidental recorded a pre-tax gain of $225 million when the sale closed in February 2011.  Net revenues and pre-tax income for discontinued operations related to Argentina were $97 million and $2 million, respectively, for the year ended December 31, 2011.  Net revenues and pre-tax losses for such discontinued operations in 2010 were $700 million and $(39) million, respectively.

In December 2010, Occidental purchased additional noncontrolling interests in the general partner of Plains All-American Pipeline, L.P. (Plains Pipeline) for approximately $430 million, and now owns 35 percent of the general partner.  In December 2010, Occidental also completed its acquisition of the remaining 50-percent joint venture interest in Elk Hills Power, LLC (EHP), a limited liability company that operates a gas-fired power-generation plant in California, for approximately $175 million, bringing Occidental’s total ownership to 100 percent.  EHP is now consolidated in Occidental’s balance sheet.

In January 2010, Occidental and other consortium members signed a 20-year contract with the South Oil Company of Iraq to develop the Zubair Field in Iraq.

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INVESTMENTS AND RELATED-PARTY TRANSACTIONS

12 Months Ended

Dec. 31, 2012

INVESTMENTS AND RELATED-PARTY TRANSACTIONS

INVESTMENTS AND RELATED-PARTY TRANSACTIONS

NOTE 14 INVESTMENTS AND RELATED-PARTY TRANSACTIONS

As of December 31, 2012 and 2011, investments in unconsolidated entities comprised $1.9 billion and $2.1 billion of equity-method investments, respectively.

EQUITY INVESTMENTS

As of December 31, 2012, Occidental’s equity investments consisted mainly of a 35-percent interest in the general partner of Plains Pipeline, a 24.5-percent interest in the stock of Dolphin Energy, and various other partnerships and joint ventures.  Equity investments paid dividends of $526 million, $349 million and $217 million to Occidental in 2012, 2011 and 2010, respectively.  As of December 31, 2012, cumulative undistributed earnings of equity-method investees since their respective acquisitions were approximately $240 million.  As of December 31, 2012, Occidental’s investments in equity investees exceeded the underlying equity in net assets by $1.1 billion, of which $1 billion represented goodwill and the remainder comprised intangibles amortized over their estimated useful lives.

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)	2012		2011		2010
Revenues	$	2,667	$	2,439	$	1,759
Costs and expenses	2,310		2,046		1,482
Net income	$	357	$	393	$	277
As of December 31, (in millions)	2012		2011
Current assets	$	2,065	$	2,230
Non-current assets	$	5,104	$	4,381
Current liabilities	$	1,774	$	1,532
Long-term debt	$	2,250	$	2,305
Other non-current liabilities	$	241	$	168
Stockholders’ equity	$	2,904	$	2,606

Occidental’s investment in Dolphin, which was acquired in 2002, consists of two separate economic interests through which Occidental owns (i) a 24.5-percent undivided interest in the operations under an agreement which is proportionately consolidated in the financial statements; and (ii) a 24.5-percent interest in the stock of Dolphin Energy, which is accounted for as an equity investment.

During 2010, Occidental had a 50-percent joint interest in EHP, which was accounted for as an equity method investment.  On December 31, 2010, Occidental completed its acquisition of the remaining 50-percent interest, bringing its total ownership to 100 percent.  EHP was consolidated in Occidental’s balance sheet as of December 31, 2010.

RELATED-PARTY TRANSACTIONS

Occidental from time to time purchases oil, NGLs, power, steam and chemicals from and sells oil, NGLs, gas, chemicals and power to certain of its equity investees at market-related prices.  During 2012, 2011 and 2010, Occidental entered into the following related-party transactions and had the following amounts due from or to its related parties:

December 31, (in millions)	2012		2011		2010
Purchases (a)	$	8	$	10	$	153
Sales (b)	$	419	$	392	$	440
Services	$	17	$	10	$	2
Advances and amounts due from	$	25	$	32	$	135
Amounts due to	$	129	$	21	$	383

(a) In 2010, purchases from EHP accounted for 90 percent of total purchases.

(b) In 2012, 2011 and 2010, sales of Occidental-produced oil and NGLs to Plains Pipeline accounted for 80 percent, 76 percent and 50 percent of these totals, respectively.  Additionally, Occidental conducts marketing and trading activities with Plains Pipeline for oil and NGLs.  These transactions are reported in Occidental’s income statement on a net margin basis.  The sales amounts above include the net margins on such transactions, which were negligible.  In 2012 and 2011, sales to Dolphin Energy accounted for 12 percent and 16 percent, of total sales, respectively.  In 2010, sales to EHP and Dolphin Energy accounted for 44 percent of total sales.

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DOMESTIC AND FOREIGN INCOME TAXES

12 Months Ended

Dec. 31, 2012

DOMESTIC AND FOREIGN INCOME TAXES

DOMESTIC AND FOREIGN INCOME TAXES

NOTE 10 DOMESTIC AND FOREIGN INCOME TAXES

The domestic and foreign components of income from continuing operations before domestic and foreign income taxes and net of noncontrolling interest amounts were as follows:

For the years ended December 31, (in millions)	Domestic			Foreign		Total
2012	$	2,117	(a)	$	5,636	$	7,753
2011	$	4,806		$	6,035	$	10,841
2010	$	3,295		$	4,269	$	7,564

(a) Includes pre-tax charges of $1.8 billion for the impairment of domestic gas assets and related items.

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

For the years ended December 31, (in millions)	United States Federal			State and Local		Foreign		Total
2012
Current	$	(401	)	$	8	$	2,383	$	1,990
Deferred	1,046			41		41		1,128
	$	645		$	49	$	2,424	$	3,118
2011
Current	$	320		$	88	$	2,357	$	2,765
Deferred	1,340			47		49		1,436
	$	1,660		$	135	$	2,406	$	4,201
2010
Current	$	614		$	79	$	1,896	$	2,589
Deferred	390			4		12		406
	$	1,004		$	83	$	1,908	$	2,995

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

For the years ended December 31,	2012		2011		2010
United States federal statutory tax rate	35	%	35	%	35	%
Operations outside the United States	5		4		5
State income taxes, net of federal benefit	1		1		1
Other	(1	)	(1	)	(1	)
Worldwide effective tax rate	40	%	39	%	40	%

The tax effects of temporary differences resulting in deferred income taxes at December 31, 2012 and 2011 were as follows:

	2012					2011
Tax effects of temporary differences (in millions)	Deferred Tax Assets			Deferred Tax Liabilities		Deferred Tax Assets			Deferred Tax Liabilities
Property, plant and equipment differences	$	—		$	7,316	$	—		$	6,039
Equity investments, partnerships and foreign subsidiaries	—			351		—			351
Environmental reserves	126			—		131			—
Postretirement benefit accruals	413			—		410			—
Deferred compensation and benefits	278			—		286			—
Asset retirement obligations	367			—		318			—
Foreign tax credit carryforwards	1,277			—		1,240			—
Other tax credit carryforwards	195			—		—			—
Federal benefit of state income taxes	89			—		104			—
All other	334			161		374			116
Subtotal	3,079			7,828		2,863			6,506
Valuation allowance	(1,040		)	—		(1,003		)	—
Total deferred taxes	$	2,039		$	7,828	$	1,860		$	6,506

Included in total deferred tax assets was a current portion aggregating $250 million and $200 million as of December 31, 2012 and 2011, respectively, that was reported in other current assets.  Total deferred tax assets were $2.0 billion and $1.9 billion as of December 31, 2012 and 2011, respectively, the noncurrent portion of which is netted against deferred tax liabilities.  Occidental expects to realize the recorded deferred tax assets, net of any allowances, through future operating income and reversal of temporary differences.

Occidental had, as of December 31, 2012, foreign tax credit carryforwards of $1.3 billion, which expire in varying amounts through 2022, and various state operating loss carryforwards, which have varying carryforward periods through 2025.  Substantially all of Occidental’s valuation allowance is provided for foreign tax credit and state operating loss carryforwards.

A deferred tax liability has not been recognized for temporary differences related to unremitted earnings of certain consolidated foreign subsidiaries aggregating approximately $8.1 billion at December 31, 2012, 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 $116 million would be required, assuming utilization of available foreign tax credits.

Discontinued operations include income tax charges of $7 million and $86 million in 2012 and 2011, respectively, and  income tax benefits of $26 million in 2010.

Additional paid-in capital was credited $8 million in 2012, $14 million in 2011 and $22 million in 2010 for an excess tax benefit from the exercise of certain stock-based compensation awards.

As of December 31, 2012, Occidental had liabilities for unrecognized tax benefits of approximately $76 million included in deferred credits and other liabilities — other, all of which, if subsequently recognized, would favorably affect Occidental’s effective tax rate.

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

For the years ended December 31, (in millions)	2012			2011
Balance at January 1,	$	67		$	38
Additions based on tax positions related to the current year	16			44
Reductions based on tax positions related to prior years and settlements	(7		)	(15		)
Balance at December 31,	$	76		$	67

Occidental records estimated potential interest and penalties related to liabilities for unrecognized tax benefits in the provisions for domestic and foreign income taxes and these amounts were not material for the years ended December 31, 2012, 2011 and 2010.

Occidental is subject to audit by various tax authorities in varying periods.  See Note 9 for a discussion of these matters.

Management believes it is unlikely that Occidental’s liabilities for unrecognized tax benefits related to existing matters would increase or decrease within the next twelve months by a material amount.  Occidental cannot reasonably estimate a range of potential changes in such benefits due to the unresolved nature of the various audits.

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LEASE COMMITMENTS

12 Months Ended

Dec. 31, 2012

LEASE COMMITMENTS

LEASE COMMITMENTS

NOTE 6 LEASE COMMITMENTS

Operating lease agreements include leases for transportation equipment, power plants, machinery, terminals, storage facilities, land and office space.  Occidental’s operating lease agreements frequently include renewal or purchase options and require it to pay for utilities, taxes, insurance and maintenance expense.  At December 31, 2012, future net minimum lease payments for noncancelable operating leases (excluding oil and gas and other mineral leases, utilities, taxes, insurance and maintenance expense) were the following:

In millions	Amount (a)
2013	$	158
2014	105
2015	106
2016	88
2017	59
Thereafter	460
Total minimum lease payments	$	976

(a) These amounts are net of sublease rentals of $3 million, which are to be received as follows (in millions):  2013—$2 and 2014—$1.

Rental expense for operating leases, net of sublease rental income for continuing operations, was $176 million in 2012, $179 million in 2011 and $170 million in 2010.  Rental expense was net of sublease income of $4 million each in 2012, 2011 and 2010.

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STOCK-BASED INCENTIVE PLANS (Details) (USD $)	0 Months Ended	1 Months Ended				12 Months Ended
	Jul. 31, 2012	Jul. 30, 2011	Oct. 31, 2010	Jul. 31, 2009	Jul. 31, 2008	Dec. 31, 2012 Y	Dec. 31, 2011 Y	Dec. 31, 2010 Y
Share-based Compensation Arrangement by Share-based Payment Award
Aggregate number of shares authorized for issuance						66,000,000
Shares issued during the period						15,000,000
Shares available for future issuance						19,000,000
Number of shares counted for every share issued						3
Number of times, as applicable, that shares fail to vest or are forfeited or cancelled, or correspond to the portion of any stock-based awards settled in cash						3
Awards of restricted stock granted to non-employee directors						53,800
Certain stock-based incentive amounts
Compensation expense (in dollars)						$ 78,000,000	$ 110,000,000	$ 136,000,000
Income tax benefit recognized in the income statement (in dollars)						29,000,000	40,000,000	50,000,000
Intrinsic value of options and stock-settled SARs exercised (in dollars)						18,000,000	21,000,000	74,000,000
Cash paid						83,000,000	124,000,000	97,000,000
Fair value of RSUs and TSRIs vested during the year						28,000,000	53,000,000	19,000,000
Unrecognized compensation expense						196,000,000
Weighted-average period over which unrecognized compensation expense is expected to be recognized (in years)						2.1
Cash-Settled RSUs
Stock-Based Awards
Award vesting period (in years)						two to three years
Performance period						7 years
Unvested RSUs and Performance-Based Awards
Unvested, beginning of period (in shares)						1,272,000
Granted (in shares)						729,000
Vested (in shares)						(621,000)
Forfeitures (in shares)						(48,000)
Unvested, end of period (in shares)						1,332,000	1,272,000
Stock awards other than options and SARs, weighted-average grant-date fair value (in dollars per share)
Unvested, beginning of period, weighted-average grant-date fair value (in dollars per share)						$ 90.50
Granted, weighted-average grant-date fair value (in dollars per share)						$ 84.38	$ 104.74	$ 77.14
Vested, weighted-average grant-date fair value (in dollars per share)						$ 83.61
Forfeitures, weighted-average grant-date fair value (in dollars per share)						$ 92.90
Unvested, end of period, weighted-average grant-date fair value (in dollars per share)						$ 90.27	$ 90.50
Stock-Settled RSUs
Unvested RSUs and Performance-Based Awards
Unvested, beginning of period (in shares)						568,000
Granted (in shares)						824,000
Vested (in shares)						(9,000)
Forfeitures (in shares)						(8,000)
Unvested, end of period (in shares)						1,375,000	568,000
Stock awards other than options and SARs, weighted-average grant-date fair value (in dollars per share)
Unvested, beginning of period, weighted-average grant-date fair value (in dollars per share)						$ 93.14
Granted, weighted-average grant-date fair value (in dollars per share)						$ 84.81	$ 102.97	$ 84.29
Vested, weighted-average grant-date fair value (in dollars per share)						$ 88.21
Forfeitures, weighted-average grant-date fair value (in dollars per share)						$ 84.57
Unvested, end of period, weighted-average grant-date fair value (in dollars per share)						$ 88.23	$ 93.14
Cash-settled SARs
Stock-Based Awards
Maximum term of award (in years)						10
Option and SAR transactions
Beginning balance (in shares)						564,000
Exercised (in shares)						(70,000)
Ending balance (in shares)						494,000
Exercisable, end of period (in shares)						494,000
Option and SAR transactions
Beginning balance, weighted average exercise price (in dollars per share)						$ 24.66
Exercised, weighted average exercise price (in dollars per share)						$ 24.66
Ending balance, weighted average exercise price (in dollars per share)						$ 24.66
Exercisable, end of period, weighted average exercise price (in dollars per share)						$ 24.66
Ending balance, weighted average remaining contractual term (in years)						1.5
Exercisable, end of period, weighted average remaining contractual term (in years)						1.5
Ending balance, aggregate intrinsic value (in dollars)						25,639,000
Exercisable, end of period, aggregate intrinsic value (in dollars)						25,639,000
Stock-settled SARs and Options
Stock-Based Awards
Award vesting period (in years)						three years
Option and SAR transactions
Beginning balance (in shares)						782,000
Exercised (in shares)						(245,000)
Ending balance (in shares)						537,000
Exercisable, end of period (in shares)						537,000
Option and SAR transactions
Beginning balance, weighted average exercise price (in dollars per share)						$ 26.34
Exercised, weighted average exercise price (in dollars per share)						$ 14.22
Ending balance, weighted average exercise price (in dollars per share)						$ 31.88
Exercisable, end of period, weighted average exercise price (in dollars per share)						$ 31.88
Ending balance, weighted average remaining contractual term (in years)						2.0
Exercisable, end of period, weighted average remaining contractual term (in years)						2.0
Ending balance, aggregate intrinsic value (in dollars)						24,008,000
Exercisable, end of period, aggregate intrinsic value (in dollars)						$ 24,008,000
TSRIs
Stock-Based Awards
Award vesting period (in years)						three to four years
Unvested RSUs and Performance-Based Awards
Unvested, beginning of period (in shares)						1,865,000
Granted (in shares)						453,000
Vested (in shares)						(388,000)
Unvested, end of period (in shares)						1,930,000	1,865,000
Stock awards other than options and SARs, weighted-average grant-date fair value (in dollars per share)
Granted, weighted-average grant-date fair value (in dollars per share)						$ 84.57	$ 102.97	$ 84.29
Unvested RSUs weighted-average grant-date fair value of Occidental stock (in dollars per share)
Unvested, beginning of period, weighted-average grant-date fair value (in dollars per share)						$ 78.67
Vested, weighted-average grant-date fair value (in dollars per share)						$ 77.00
Unvested, end of period, weighted-average grant-date fair value (in dollars per share)						$ 80.39	$ 78.67
Grant-date assumptions used in the Monte Carlo simulation models
Risk-free interest rate (as a percent)						0.40%	0.60%	0.60%
Dividend yield (as a percent)						2.60%	1.80%	1.80%
Volatility factor (as a percent)						34.00%	33.00%	32.00%
Expected life (in years)						3	3	3
Other disclosures
Payouts for Performance-based awards granted, low end of range (as a percent)	0.00%	0.00%	0.00%	0.00%
Payouts for Performance-based awards granted, high end of range (as a percent)	100.00%	100.00%	100.00%	200.00%	150.00%
Payouts for Performance-based awards granted (as a percent)					150.00%
Performance-based awards settled in stock (as a percent)		50.00%	50.00%	60.00%
Performance-based awards settled for cash (as a percent)		50.00%	50.00%	40.00%

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INVENTORIES

12 Months Ended

Dec. 31, 2012

INVENTORIES

INVENTORIES

NOTE 4 INVENTORIES

Net carrying values of inventories valued under the LIFO method were approximately $185 million and $176 million at December 31, 2012 and 2011, respectively.  Inventories consisted of the following:

Balance at December 31, (in millions)	2012			2011
Raw materials	$	70		$	69
Materials and supplies	612			443
Finished goods	763			655
	1,445			1,167
LIFO reserve	(101		)	(98		)
Total	$	1,344		$	1,069

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LONG-TERM DEBT

12 Months Ended

Dec. 31, 2012

LONG-TERM DEBT

LONG-TERM DEBT

NOTE 5 LONG-TERM DEBT

Long-term debt consisted of the following:

Balance at December 31, (in millions)	2012			2011
4.10% senior notes due 2021	$	1,300		$	1,300
1.75% senior notes due 2017	1,250			1,250
2.70% senior notes due 2023	1,250			—
3.125% senior notes due 2022	900			900
4.125% senior notes due 2016	750			750
2.5% senior notes due 2016	700			700
1.45% senior notes due 2013	600			600
1.50% senior notes due 2018	500			—
8.45% senior notes due 2029	116			116
9.25% senior debentures due 2019	116			116
7.2% senior debentures due 2028	82			82
Variable rate bonds due 2030 (0.13% and 0.11% as of December 31, 2012 and 2011, respectively)	68			68
8.75% medium-term notes due 2023	22			22
	7,654			5,904
Less:
Unamortized discount, net	(31		)	(33		)
Current maturities	(600		)	—
Total	$	7,023		$	5,871

Occidental has a bank credit facility (Credit Facility) with a $2.0 billion commitment expiring in 2016.  No amounts have been drawn under this Credit Facility. Up to $1.0 billion 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 average annual facility fees of 0.08 percent in 2012 on the total commitment amounts of the Credit Facility.

The Credit Facility provides for the termination of loan commitments and requires immediate repayment of any outstanding amounts if certain events of default occur.  The Credit Facility and other debt agreements do not contain material adverse change clauses or debt ratings triggers that could restrict Occidental’s ability to borrow or that would permit lenders to terminate their commitments or accelerate debt.

As of December 31, 2012, under the most restrictive covenants of its financing agreements, Occidental had substantial capacity for additional unsecured borrowings, the payment of cash dividends and other distributions on, or acquisitions of, Occidental stock.

In June 2012, Occidental issued $1.75 billion of debt which comprised $1.25 billion of 2.70-percent senior unsecured notes due 2023 and $500 million of 1.50-percent senior unsecured notes due 2018.  Occidental received net proceeds of approximately $1.74 billion.  Interest on the notes will be payable semi-annually in arrears in February and August for each series of notes.

In August 2011, Occidental issued $2.15 billion of debt, which comprised $1.25 billion of 1.75-percent senior unsecured notes due 2017 and $900 million of 3.125-percent senior unsecured notes due 2022.  Occidental received net proceeds of approximately $2.1 billion.  Interest on the notes is payable semi-annually in arrears in February and August for each series of notes.

In March 2011, Occidental redeemed all $1.0 billion of its outstanding 7-percent senior notes due 2013 and all $368 million of its outstanding 6.75-percent senior notes due 2012.  Occidental recorded a $163 million pre-tax charge related to this redemption in the first quarter of 2011.

In December 2010, Occidental issued $2.6 billion of debt, which comprised $600 million of 1.45-percent senior unsecured notes due 2013, $700 million of 2.50-percent senior unsecured notes due 2016 and $1.3 billion of 4.10-percent senior unsecured notes due 2021.  Occidental received net proceeds of approximately $2.6 billion.  Interest on the notes is payable semi-annually in arrears in June and December of each year for the 1.45-percent notes and February and August of each year for the other notes.

Occidental has provided guarantees on Dolphin Energy’s debt, which are limited to certain political and other events.  At December 31, 2012 and 2011, Occidental’s total guarantees were not material and a substantial majority of the amounts consisted of limited recourse guarantees on approximately $370 million and $300 million, respectively, of Dolphin’s debt, of which the fair value was immaterial.

At December 31, 2012, principal payments on long-term debt aggregated $7.6 billion, of which $0.6 billion is due in 2013, $0.0 billion in 2014, $0.0 billion in 2015, $1.4 billion in 2016, $1.2 billion in 2017 and $4.4 billion in 2018 and thereafter.

Occidental estimates the fair value of fixed-rate debt based on the quoted market prices for those instruments or on quoted market yields for similarly rated debt instruments, taking into account such instruments’ maturities.  The estimated fair values of Occidental’s debt at December 31, 2012 and 2011, which were classified as Level 1, were approximately $8.2 billion and $6.4 billion, respectively, compared to carrying values of approximately $7.6 billion and $5.9 billion, respectively.  Occidental’s exposure to changes in interest rates relates primarily to its variable-rate, long-term debt obligations, and is not material.  As of December 31, 2012 and 2011, variable-rate debt constituted approximately 1 percent of Occidental’s total debt.

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DERIVATIVES

12 Months Ended

Dec. 31, 2012

DERIVATIVES

DERIVATIVES

NOTE 7 DERIVATIVES

Objective & Strategy

Occidental uses a variety of derivative instruments, including cash-flow hedges and derivative instruments not designated as hedging instruments, to establish, as of the date of production, the price it receives and to improve realized prices for oil and gas.  Occidental only occasionally hedges its oil and gas production and, when it does, the volumes are usually insignificant.  Additionally, Occidental’s Phibro trading unit engages in trading activities using derivatives for the purpose of generating profits mainly from market price changes of commodities.

Refer to Note 1 for Occidental’s accounting policy on derivatives.

Cash-Flow Hedges

Occidental entered into financial swap agreements in November 2012 for the sale of a portion of its natural gas production in California.  These swap agreements hedge 50 million cubic feet of natural gas per day beginning in January 2013 through March 2014 and qualify as cash-flow hedges.  The weighted-average strike price of these swaps was $4.30.

Through March 31, 2012, Occidental held financial swap agreements related to the sale of 50 million cubic feet per day of its existing natural gas production from the Rocky Mountain region of the United States that qualified as cash-flow hedges  at a weighted-average strike price of $6.07.

Through December 31, 2011, Occidental held a series of collar agreements for 12,000 barrels of oil per day of its domestic production that qualified as cash-flow hedges at a weighted-average strike price that ranged from $32.92 to $46.35.

Occidental’s marketing and trading operations store natural gas purchased from third parties at Occidental’s North American leased storage facilities.  Derivative instruments are used to fix margins on the future sales of the stored volumes through March 31, 2013.  As of December 31, 2012 and 2011, Occidental had approximately 20 billion cubic feet and 25 billion cubic feet of natural gas held in storage, respectively.  As of December 31, 2012 and 2011, Occidental had cash-flow hedges for the forecast sale, to be settled by physical delivery, of approximately 20 billion cubic feet and 35 billion cubic feet of this stored natural gas, respectively.

The following table presents the pre-tax and after-tax gains and losses recognized in, and reclassified to income from, AOCI, for derivative instruments classified as cash-flow hedges for the years ended December 31, 2012 and 2011 (in millions):

	After-tax						Pre-Tax
	2012			2011			2012			2011
Beginning Balance - AOCI	$	1		$	(111	)
Unrealized gains recognized in AOCI	16			14			$	25		$	20
(Gains) losses reclassified to income	(24		)	98			$	(38	)	$	154
Ending Balance - AOCI	$	(7	)	$	1

Occidental expects that during the next twelve months an insignificant amount of net after-tax derivative losses included in AOCI based on their valuation as of December 31, 2012, will be reclassified into income.  The gains and losses reclassified to income were recognized in net sales, and the amount of the ineffective portion of cash-flow hedges was immaterial for the years ended December 31, 2012 and 2011.

Derivatives Not Designated as Hedging Instruments

The following table summarizes Occidental’s net volumes resulting from outstanding commodity derivatives contracts not designated as hedging instruments, including both financial and physical derivative contracts as of December 31, 2012 and 2011:

	Net Outstanding Position Long / (Short)
Commodity	2012		2011
Oil (million barrels)	(17	)	(9	)
Natural gas (billion cubic feet)	(217	)	(242	)
Precious metals (million troy ounces)	1		3

In addition, Occidental typically has certain other commodity trading contracts, such as agricultural products, power and other metals, as well as foreign exchange contracts.  These contracts were not material to Occidental as of December 31, 2012 and 2011.

Occidental fulfills its short positions through its own production or by third-party purchase contracts. Subsequent to December 31, 2012, Occidental entered into purchase contracts for a substantial portion of the outstanding positions at year-end and has sufficient production capacity and the ability to enter into additional purchase contracts to satisfy the remaining positions.

Approximately $49 million and $94 million of net gains from derivatives not designated as hedging instruments were recognized in net sales for the years ended December 31, 2012 and 2011, respectively.

Fair Value of Derivatives

The following table presents the gross fair value of Occidental’s outstanding derivatives as of December 31, 2012 and 2011 (in millions):

December 31, 2012	Asset Derivatives Balance Sheet Location	Fair Value			Liability Derivatives Balance Sheet Location	Fair Value
Cash-flow hedges (a)
	Other current assets	$	11		Accrued liabilities	$	1
Commodity contracts	Long-term receivables and other assets, net	—			Deferred credits and other liabilities	1
		$	11			$	2
Derivatives not designated as hedging instruments (a)
	Other current assets	$	386		Accrued liabilities	$	479
Commodity contracts	Long-term receivables and other assets, net	22			Deferred credits and other liabilities	16
		408				495
Total gross fair value		419				497
Less: counterparty netting and cash collateral (b)		(301		)		(371		)
Total net fair value of derivatives		$	118			$	126

December 31, 2011	Asset Derivatives Balance Sheet Location	Fair Value			Liability Derivatives Balance Sheet Location	Fair Value
Cash-flow hedges (a)
	Other current assets	$	41		Accrued liabilities	$	5
Commodity contracts	Long-term receivables and other assets, net	3			Deferred credits and other liabilities	—
		$	44			$	5
Derivatives not designated as hedging instruments (a)
	Other current assets	$	835		Accrued liabilities	$	887
Commodity contracts	Long-term receivables and other assets, net	71			Deferred credits and other liabilities	71
		906				958
Total gross fair value		950				963
Less: counterparty netting and cash collateral (c)		(758		)		(782		)
Total net fair value of derivatives		$	192			$	181

(a) Fair values are presented at gross amounts, including when the derivatives are subject to master netting arrangements and qualify for net presentation in the consolidated balance sheet.

(b) As of December 31, 2012, collateral received of $25 million has been netted against derivative assets and collateral paid of $95 million has been netted against derivative liabilities.

(c) As of December 31, 2011, collateral received of $42 million has been netted against derivative assets and collateral paid of $66 million has been netted against derivative liabilities.

See Note 15 for fair value measurement disclosures on derivatives.

Credit Risk

A substantial portion of Occidental’s derivative transaction volume is executed through exchange-traded contracts, which are subject to nominal credit risk as a significant portion of these transactions is settled on a daily margin basis with select clearinghouses and brokers.  Collateral of $116 million and $173 million deposited by Occidental for such contracts, which has not been reflected in the derivative fair value tables, is included in the other current assets balance as of December 31, 2012 and 2011, respectively.

Occidental executes the rest of its derivative transactions in the OTC market.  Occidental is subject to counterparty credit risk to the extent the counterparty to the derivatives is unable to meet its settlement commitments.  Occidental manages this credit risk by selecting counterparties that it believes to be financially strong, by spreading the credit risk among many such counterparties, by entering into master netting arrangements with the counterparties and by requiring collateral, as appropriate.  Occidental actively monitors the creditworthiness of each counterparty and records valuation adjustments to reflect counterparty risk, if necessary.

Certain of Occidental’s OTC derivative instruments contain credit-risk-contingent features, primarily tied to credit ratings for Occidental or its counterparties, which may affect the amount of collateral that each would need to post.  As of December 31, 2012 and 2011, Occidental had a net liability of $34 million and $58 million, respectively, which are net of collateral posted of $64 million and $27 million, respectively.  Occidental believes that if it had received a one-notch reduction in its credit ratings, it would not have resulted in a material change in its collateral-posting requirements as of December 31, 2012 and 2011.

Foreign Currency Risk

Occidental’s foreign operations have limited currency risk.  Occidental manages its exposure primarily by balancing monetary assets and liabilities and limiting cash positions in foreign currencies to levels necessary for operating purposes.  A vast majority of international oil sales are denominated in United States dollars.  Additionally, all of Occidental’s consolidated foreign oil and gas subsidiaries have the United States dollar as the functional currency.

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FAIR VALUE MEASUREMENTS (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended										12 Months Ended
	Dec. 31, 2012	Dec. 31, 2010	Dec. 31, 2012 Recurring Level 1	Dec. 31, 2011 Recurring Level 1	Dec. 31, 2012 Recurring Level 2	Dec. 31, 2011 Recurring Level 2	Dec. 31, 2012 Recurring Netting and Collateral	Dec. 31, 2011 Recurring Netting and Collateral	Dec. 31, 2012 Recurring Total Fair Value	Dec. 31, 2011 Recurring Total Fair Value	Dec. 31, 2012 Non recurring	Dec. 31, 2010 Non recurring
Assets:
Commodity derivatives			$ 107	$ 310	$ 312	$ 640	$ (301)	$ (758)	$ 118	$ 192
Liabilities:
Commodity derivatives			99	311	398	652	(371)	(782)	126	181
Asset impairments and related items	$ 1,751	$ 275									$ 1,731	$ 275
Percentage of pre-tax impairment charges related to natural gas properties											90.00%
Average period over which natural gas properties were acquired											4 years

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INDUSTRY SEGMENTS AND GEOGRAPHIC AREAS (Details 2) (USD $) In Millions, unless otherwise specified	3 Months Ended	12 Months Ended
	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Segment Information
Net sales		$ 24,172	$ 23,939	$ 19,045
Property, plant and equipment, net		52,064	45,684	36,536
Corporate significant items affecting earnings/Pre-tax operating profit (loss)
Corporate significant items affecting earnings/premium on debt extinguishment	(163)
United States
Segment Information
Net sales		15,359	15,040	12,151
Property, plant and equipment, net		40,786	36,283	28,571
Total Foreign
Segment Information
Net sales		8,813	8,899	6,894
Property, plant and equipment, net		11,278	9,401	7,965
Qatar
Segment Information
Net sales		3,356	3,432	2,667
Property, plant and equipment, net		2,676	2,735	2,823
Oman
Segment Information
Net sales		2,578	2,500	1,666
Property, plant and equipment, net		2,353	2,143	1,967
Colombia
Segment Information
Net sales		1,027	1,054	999
Property, plant and equipment, net		1,041	854	715
Yemen
Segment Information
Net sales		407	907	766
Property, plant and equipment, net		199	245	347
Bahrain
Segment Information
Net sales		215	187	100
Property, plant and equipment, net		688	477	222
United Arab Emirates
Segment Information
Property, plant and equipment, net		2,104	971	1
Other Foreign
Segment Information
Net sales		1,230	819	686
Property, plant and equipment, net		2,217	1,976	1,890
Corporate
Corporate significant items affecting earnings/Pre-tax operating profit (loss)
Corporate significant items affecting earnings/Pre-tax operating profit (loss) total		(20)	(163)
Corporate significant items affecting earnings/Income Taxes
State income tax charge			(33)
Foreign tax credit carryforwards				80
Tax effect of pre-tax adjustments		636	50	100
Corporate significant items affecting earnings/Income Taxes Total		636	17	180
Corporate | Litigation reserves
Corporate significant items affecting earnings/Pre-tax operating profit (loss)
Corporate significant items affecting earnings/Litigation reserves		(20)
Corporate | Premium on debt extinguishments
Corporate significant items affecting earnings/Pre-tax operating profit (loss)
Corporate significant items affecting earnings/premium on debt extinguishment			$ (163)

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INVESTMENTS AND RELATED-PARTY TRANSACTIONS (Details) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
RELATED-PARTY TRANSACTIONS
Purchases from EHP as percent of total related party purchase			90.00%
Purchases from related parties	$ 8,000,000	$ 10,000,000	$ 153,000,000
Sales to related parties	419,000,000	392,000,000	440,000,000
Services to related parties	17,000,000	10,000,000	2,000,000
Advances and amounts due from related parties	25,000,000	32,000,000	135,000,000
Amounts due to related parties	129,000,000	21,000,000	383,000,000
Equity Method Investments
Equity method investment amounts	1,900,000,000	2,100,000,000
Equity investments dividends paid	526,000,000	349,000,000	217,000,000
Cumulative undistributed earnings of equity-method investees	240,000,000
Excess of investments in equity investees over the underlying equity in net assets	1,100,000,000
Excess of investments in equity investees over the underlying equity in net assets, which represents goodwill	1,000,000,000
Equity-method investments financial information summarized by Income Statement line item
Revenues	2,667,000,000	2,439,000,000	1,759,000,000
Costs and expenses	2,310,000,000	2,046,000,000	1,482,000,000
Net income	357,000,000	393,000,000	277,000,000
Equity-method investments financial information summarized by Balance Sheet line item
Current assets	2,065,000,000	2,230,000,000
Non-current assets	5,104,000,000	4,381,000,000
Current liabilities	1,774,000,000	1,532,000,000
Long-term debt	2,250,000,000	2,305,000,000
Other non-current liabilities	241,000,000	168,000,000
Stockholders' equity	$ 2,904,000,000	$ 2,606,000,000
EHP and Dolphin Energy
RELATED-PARTY TRANSACTIONS
Sales to related party (as a percent)			44.00%
Dolphin Energy
EQUITY INVESTMENTS
Equity method investment ownership percentage	24.50%
Ownership interest in oil and gas properties (as a percent)	24.50%
Number of separate economic interests comprising investment in unconsolidated affiliate	2
RELATED-PARTY TRANSACTIONS
Sales to related party (as a percent)	12.00%	16.00%
Elk Hills Power
EQUITY INVESTMENTS
Equity method investment additional ownership percentage			50.00%
Total ownership percentage			100.00%
General Partner of Plains All American Pipeline
EQUITY INVESTMENTS
Equity method investment ownership percentage	35.00%
RELATED-PARTY TRANSACTIONS
Sales to related party (as a percent)	80.00%	76.00%	50.00%

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DOMESTIC AND FOREIGN INCOME TAXES (Tables)

12 Months Ended

Dec. 31, 2012

DOMESTIC AND FOREIGN INCOME TAXES

Domestic and foreign components of income from continuing operations before domestic and foreign income taxes and net of noncontrolling interest amounts

For the years ended December 31, (in millions)	Domestic			Foreign		Total
2012	$	2,117	(a)	$	5,636	$	7,753
2011	$	4,806		$	6,035	$	10,841
2010	$	3,295		$	4,269	$	7,564

(a) Includes pre-tax charges of $1.8 billion for the impairment of domestic gas assets and related items.

Provisions (credits) for domestic and foreign income taxes on continuing operations

For the years ended December 31, (in millions)	United States Federal			State and Local		Foreign		Total
2012
Current	$	(401	)	$	8	$	2,383	$	1,990
Deferred	1,046			41		41		1,128
	$	645		$	49	$	2,424	$	3,118
2011
Current	$	320		$	88	$	2,357	$	2,765
Deferred	1,340			47		49		1,436
	$	1,660		$	135	$	2,406	$	4,201
2010
Current	$	614		$	79	$	1,896	$	2,589
Deferred	390			4		12		406
	$	1,004		$	83	$	1,908	$	2,995

Reconciliation of the United States federal statutory income tax rate to Occidental's worldwide effective tax rate on income from continuing operations is stated as a percentage of pre-tax income

For the years ended December 31,	2012		2011		2010
United States federal statutory tax rate	35	%	35	%	35	%
Operations outside the United States	5		4		5
State income taxes, net of federal benefit	1		1		1
Other	(1	)	(1	)	(1	)
Worldwide effective tax rate	40	%	39	%	40	%

Tax effects of temporary differences resulting in deferred income taxes

	2012					2011
Tax effects of temporary differences (in millions)	Deferred Tax Assets			Deferred Tax Liabilities		Deferred Tax Assets			Deferred Tax Liabilities
Property, plant and equipment differences	$	—		$	7,316	$	—		$	6,039
Equity investments, partnerships and foreign subsidiaries	—			351		—			351
Environmental reserves	126			—		131			—
Postretirement benefit accruals	413			—		410			—
Deferred compensation and benefits	278			—		286			—
Asset retirement obligations	367			—		318			—
Foreign tax credit carryforwards	1,277			—		1,240			—
Other tax credit carryforwards	195			—		—			—
Federal benefit of state income taxes	89			—		104			—
All other	334			161		374			116
Subtotal	3,079			7,828		2,863			6,506
Valuation allowance	(1,040		)	—		(1,003		)	—
Total deferred taxes	$	2,039		$	7,828	$	1,860		$	6,506

Reconciliation of the beginning and ending amount of unrecognized tax benefits

For the years ended December 31, (in millions)	2012			2011
Balance at January 1,	$	67		$	38
Additions based on tax positions related to the current year	16			44
Reductions based on tax positions related to prior years and settlements	(7		)	(15		)
Balance at December 31,	$	76		$	67

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DERIVATIVES (Details)	Dec. 31, 2012 ft3	Dec. 31, 2011 ft3	Dec. 31, 2011 Crude Oil - Collars 2011 (in barrels) bbl	Mar. 31, 2012 Natural Gas - Swaps January 2012- March 2012 (in cubic feet) ft3	Nov. 30, 2012 Natural Gas - Swaps January 2013- March 2014 (in cubic feet) ft3
Cash-Flow Hedges
Daily volume			12,000	50,000,000	50,000,000
Average Floor (in dollars per barrel)			32.92
Average Cap (in dollars per barrel)			46.35
Average Price (in dollars per cubic foot)				0.006070	0.004300
Natural gas held in storage (in cubic feet)	20,000,000,000	25,000,000,000
Forecast sale of natural gas from storage designated as cash-flow hedges (in cubic feet)	20,000,000,000	35,000,000,000

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STOCK-BASED INCENTIVE PLANS

12 Months Ended

Dec. 31, 2012

STOCK-BASED INCENTIVE PLANS

STOCK-BASED INCENTIVE PLANS

NOTE 12 STOCK-BASED INCENTIVE PLANS

Occidental has established several Plans that allow it to issue stock-based awards in the form of RSUs, stock options (Options), stock appreciation rights (SARs) and TSRIs.  An aggregate of 66 million shares of Occidental common stock were authorized for issuance and approximately 15 million shares had been issued through December 31, 2012.  Of the remaining shares, approximately 19 million shares are available for grants of future awards because a plan provision requires each share covered by an award (other than Options and SARs) to be counted as if three shares were issued in determining the number of shares that otherwise would have been available for future awards.  Further, the number of shares available for future awards may be less than 19 million depending on the type of award granted.  Additionally, under the plan, the shares available for future awards may increase by the number of shares currently unvested or forfeitable, or three times that number as applicable, that (i) fail to vest, (ii) are forfeited or cancelled, or (iii) correspond to the portion of any stock-based awards settled in cash.

During 2012, non-employee directors were granted awards for 53,800 shares of restricted stock that fully vested on the grant date.  Compensation expense for these awards was measured using the quoted market price of Occidental’s common stock on the grant date and was fully recognized at that time.

The following table summarizes certain stock-based incentive amounts for the past three years:

For the years ended December 31, (in millions)	2012		2011		2010
Compensation expense	$	78	$	110	$	136
Income tax benefit recognized in the income statement	$	29	$	40	$	50
Intrinsic value of options and stock-settled SARs exercised	$	18	$	21	$	74
Cash paid (a)	$	83	$	124	$	97
Fair value of RSUs and TSRIs vested during the year (b)	$	28	$	53	$	19

(a) Includes cash paid under the cash-settled portion of the SARs, RSUs and TSRIs.

(b) As measured on the vesting date for the stock-settled portion of the RSUs and TSRIs.

As of December 31, 2012, unrecognized compensation expense for all unvested stock-based incentive awards, based on year-end valuation, was $196 million.  This expense is expected to be recognized over a weighted-average period of 2.1 years.

RSUs

Certain employees are awarded the right to receive RSUs, some of which have performance criteria, and are, or are equivalent in value to, actual shares of Occidental common stock and are settled in cash or stock at the time of vesting.  These awards vest at the end of, or ratably over, two or three years from the grant date, however, certain of the RSUs are forfeitable if performance objectives are not satisfied between the third and seventh anniversaries after the grant date.  For those awards that cliff vest in two years, dividend equivalents are accumulated during the vesting period and are paid when they vest.  For the remaining RSUs, dividend equivalents are paid during the vesting period.  The weighted-average, grant-date fair values of cash-settled RSUs granted in 2012, 2011 and 2010 were $84.38, $104.74 and $77.14 per share, respectively.  The weighted-average, grant-date fair values of the stock-settled RSUs granted in 2012, 2011, and 2010 were $84.81, $102.97 and $84.29 respectively.

A summary of changes in Occidental’s unvested cash- and stock-settled RSUs during the year ended December 31, 2012 is presented below:

	Cash-Settled				Stock-Settled
	RSUs (000’s)		Weighted-Average Grant-Date Fair Value		RSUs (000’s)		Weighted-Average Grant-Date Fair Value
Unvested at January 1	1,272		$	90.50	568		$	93.14
Granted	729		$	84.38	824		$	84.81
Vested	(621	)	$	83.61	(9	)	$	88.21
Forfeitures	(48	)	$	92.90	(8	)	$	84.57
Unvested at December 31	1,332		$	90.27	1,375		$	88.23

STOCK OPTIONS AND SARs

Certain employees have been granted Options that are settled in stock and SARs that are settled either only in stock or only in cash.  No Options or SARs have been granted since 2006 and all outstanding awards are vested.  Exercise prices of the Options and SARs were equal to the quoted market value of Occidental’s stock on the grant date.  Generally, the Options and SARs vest ratably over three years from the grant date 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, stock-settled SAR or cash-settled SAR is initially measured on the grant date using the Black Scholes option valuation model.  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 T-notes (US Treasury Strip) at the grant date with a remaining term equal to the expected life of the measured instrument.  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 may not accurately predict the value ultimately realized by employees who receive stock-based incentive awards, and the ultimate value may not be indicative of the reasonableness of the original estimates of fair value made by Occidental.

The following is a summary of Option and SAR transactions during the year ended December 31, 2012:

	Cash-Settled							Stock-Settled
	SARs (000’s)		Weighted- Average Exercise Price		Weighted- Average Remaining Contractual Term (yrs)	Aggregate Intrinsic Value (000’s)		SARs & Options (000’s)		Weighted- Average Exercise Price		Weighted- Average Remaining Contractual Term (yrs)	Aggregate Intrinsic Value (000’s)
Beginning balance, January 1	564		$	24.66				782		$	26.34
Exercised	(70	)	$	24.66				(245	)	$	14.22
Ending balance, December 31	494		$	24.66	1.5	$	25,639	537		$	31.88	2.0	$	24,008
Exercisable at December 31	494		$	24.66	1.5	$	25,639	537		$	31.88	2.0	$	24,008

TSRIs

Certain executives are awarded TSRIs that vest at the end of the three- or four-year period following the grant date if performance targets are certified as being met.  TSRIs granted in July 2012 have payouts that range from 0 to 100 percent of the maximum award that would settle, once certified, fully in stock.  TSRIs granted in July 2011 and October 2010 have payouts that range from 0 to 100 percent of the maximum award that would settle, once certified, 50 percent in stock and 50 percent in cash.  TSRIs granted in July 2009 have payouts that ranged from 0 to 200 percent of the target award that would settle, once certified, 60 percent in stock and 40 percent in cash.  TSRIs granted in July 2008 had payouts of 150 percent of the target award and were certified and settled equally in stock and cash in 2012.  Dividend equivalents for TSRI target shares are paid during the performance period regardless of the payout range or settlement provision, except for the TSRIs issued in 2010, 2011 and 2012, for which cumulative dividends will be paid upon vesting for the number of vested shares.

The fair values of TSRIs are initially determined on the grant date using a Monte Carlo simulation model based on Occidental’s assumptions, noted in the following table, and the volatility from corresponding peer group companies.  The expected life is based on the vesting period (Term).  The risk-free interest rate is the implied yield available on zero coupon T-notes (US Treasury Strip) 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 may not accurately predict the value ultimately realized by the employees who receive the awards, and the ultimate value 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 models for the estimated payout level of TSRIs were as follows:

	TSRIs
Year Granted	2012			2011			2010
Assumptions used:
Risk-free interest rate	0.4		%	0.6		%	0.6		%
Dividend yield	2.6		%	1.8		%	1.8		%
Volatility factor	34		%	33		%	32		%
Expected life (years)	3			3			3
Grant-date fair value of underlying Occidental common stock	$	84.57		$	102.97		$	84.29

A summary of Occidental’s unvested TSRIs as of December 31, 2012 and changes during the year ended December 31, 2012 is presented below:

	TSRIs
	Awards (000’s)		Weighted-Average Grant-Date Fair Value of Occidental Stock
Unvested at January 1 (a)	1,865		$	78.67
Granted (a)	453		$	84.57
Vested (b)	(388	)	$	77.00
Forfeitures	—		$	—
Unvested at December 31 (a)	1,930		$	80.39

(a) Unvested awards and award grants are presented at the target or mid-point payouts.

(b) The payout at vesting was 150 percent of the target for TSRIs.

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Schedule II - Valuation and Qualifying Accounts

12 Months Ended

Dec. 31, 2012

Schedule II - Valuation and Qualifying Accounts

Schedule II - Valuation and Qualifying Accounts

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 (a)			Balance at End of Period
2012
Allowance for doubtful accounts	$	16	$	—		$	—	$	—		$	16
Environmental	$	360	$	56		$	—	$	(72	)	$	344
Litigation, tax and other reserves	198		57			—		(26		)	229
	$	558	$	113		$	—	$	(98	)	$	573	(b)
2011
Allowance for doubtful accounts	$	19	$	—		$	—	$	(3	)	$	16
Environmental	$	366	$	53		$	14	$	(73	)	$	360
Litigation, tax and other reserves	193		37			—		(32		)	198
	$	559	$	90		$	14	$	(105	)	$	558	(b)
2010
Allowance for doubtful accounts	$	30	$	(9	)	$	—	$	(2	)	$	19
Environmental	$	403	$	26		$	3	$	(66	)	$	366
Litigation, tax and other reserves	226		20			6		(59		)	193
	$	629	$	46		$	9	$	(125	)	$	559	(b)

Note:  The amounts presented represent continuing operations.

(a) Primarily represents payments.

(b) Of these amounts, $98 million, $100 million and $102 million in 2012, 2011 and 2010, respectively, are classified as current.

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LONG-TERM DEBT (Details 3) (USD $)	Dec. 31, 2012	Dec. 31, 2011
Principal payments on long-term debt
Due in 2013	$ 600,000,000
Due in 2014	0
Due in 2015	0
Due in 2016	1,400,000,000
Due in 2017	1,200,000,000
Due in 2018 and thereafter	4,400,000,000
Aggregate future principal payments	7,600,000,000
Other Fixed-Rate and Variable-Rate Debt Disclosures
Estimated fair values of long-term debt	8,200,000,000	6,400,000,000
Debt carrying value	$ 7,654,000,000	$ 5,904,000,000
Variable-rate debt as percent of Occidental's total debt	1.00%	1.00%

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011 Item Y	Dec. 31, 2010
RISKS AND UNCERTAINTIES
Assets, relating to operations in countries outside North America	$ 12,300,000,000
Net sales, relating to operations in countries outside North America	8,800,000,000
CASH AND CASH EQUIVALENTS
Total cash equivalents	1,000,000,000	3,500,000,000
PROPERTY, PLANT AND EQUIPMENT
Maximum time period after which costs of exploratory wells are charged to expense if determination of proved reserves has not been made (in months)		12
Net capitalized costs attributable to unproved properties	4,800,000,000
Capitalized exploratory well costs for the years ended December 31:
Balance - Beginning of Year	182,000,000	73,000,000	51,000,000
Additions to capitalized exploratory well costs pending the determination of proved reserves	400,000,000	334,000,000	112,000,000
Reclassifications to property, plant and equipment based on the determination of proved reserves	(407,000,000)	(204,000,000)	(73,000,000)
Capitalized exploratory well costs charged to expense	(77,000,000)	(21,000,000)	(17,000,000)
Balance - End of Year	98,000,000	182,000,000	73,000,000
The estimated useful lives of Occidental's chemical assets, low end of range (in years)		3
The estimated useful lives of Occidental's chemical assets, high end of range (in years)		50
ACCRUED LIABILITIES-CURRENT
Accrued liabilities for accrued payroll, commissions and related expenses	385,000,000	462,000,000
ENVIRONMENTAL LIABILITIES AND EXPENDITURES
Period exceeding the minimum period often taken for comprehensive environmental response for CERCLA sites (in years)		10
ASSET RETIREMENT OBLIGATIONS
Asset retirement obligation, included in deferred credits and other liabilities-other	1,212,000,000	1,030,000,000
For the years ended December 31, (in millions)
Beginning balance	1,089,000,000	800,000,000
Liabilities incurred - capitalized to PP&E	86,000,000	74,000,000
Liabilities settled and paid	(58,000,000)	(53,000,000)
Accretion expense	61,000,000	48,000,000
Acquisitions and other - capitalized to PP&E	50,000,000	177,000,000
Revisions to estimated cash flows - capitalized to PP&E	38,000,000	43,000,000
Ending balance	1,266,000,000	1,089,000,000	800,000,000
DERIVATIVE INSTRUMENTS
Range used to determine if derivative instrument is effective, low end of range (as a percent)	80.00%
Range used to determine if derivative instrument is effective, high end of range (as a percent)	125.00%
Supplemental Cash Flow Information.
Interest Paid	190,000,000	315,000,000	161,000,000
Debt extinguishment premium
Supplemental Cash Flow Information.
Interest Paid		154,000,000
Continuing operations
Supplemental Cash Flow Information.
U.S. federal, state and foreign income taxes paid	2,400,000,000	2,900,000,000	2,400,000,000
Production, property and other taxes paid	$ 694,000,000	$ 635,000,000	$ 510,000,000

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Consolidated Statements of Income (Parenthetical) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Consolidated Statements of Income
Cost of sales, depreciation, depletion and amortization	$ 4,504	$ 3,584	$ 3,145

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

12 Months Ended

Dec. 31, 2012

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

NOTE 1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

NATURE OF OPERATIONS

In this report, “Occidental” means Occidental Petroleum Corporation, a Delaware corporation (OPC), or OPC and one or more entities in which it owns a controlling interest (subsidiaries).  Occidental conducts its operations through various subsidiaries and affiliates.  Occidental’s principal businesses consist of the oil and gas, chemical and midstream, marketing and other (midstream and marketing) segments.  The oil and gas segment explores for, develops and produces oil and condensate, natural gas liquids (NGLs) and natural gas.  The chemical segment (OxyChem) mainly manufactures and markets basic chemicals and vinyls.  The midstream and marketing  segment  gathers, processes, transports, stores, purchases and markets oil, condensate, NGLs, natural gas, carbon dioxide (CO2) and power.  It also trades around its assets, including transportation and storage capacity, and trades oil, NGLs, gas and other commodities.  The segment also invests in entities that conduct similar activities.

PRINCIPLES OF CONSOLIDATION

The consolidated financial statements have been prepared in conformity with United States generally accepted accounting principles (GAAP) and include the accounts of OPC, its subsidiaries and its undivided interests in oil and gas exploration and production ventures.  Occidental accounts for its share of oil and gas exploration and production ventures, in which it has a direct working interest, 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.

Certain financial statements, notes and supplementary data for prior years have been reclassified to conform to the 2012 presentation.

INVESTMENTS IN UNCONSOLIDATED ENTITIES

Occidental’s percentage interest in the underlying net assets of affiliates as to which it exercises significant influence without having a controlling interest (excluding oil and gas ventures in which Occidental holds an undivided interest) 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 may have occurred.  The amount of impairment, if any, is based on quoted market prices, when available, or other valuation techniques, including discounted cash flows.

REVENUE RECOGNITION

Revenue is recognized from oil and gas production when title has passed to the customer, which occurs when the product is shipped.  In international locations where oil is shipped by tanker, title passes when the tanker is loaded or product is received by the customer, depending on the shipping terms.  This process occasionally causes a difference between actual production in a reporting period and sales volumes that have been recognized as revenue.

Revenue from chemical product sales is recognized when the product is shipped and title has passed to the customer.  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.

Revenue from marketing and trading activities is recognized on net settled transactions upon completion of contract terms and, for physical deliveries, upon title transfer.  For unsettled transactions, contracts are recorded at fair value and changes in fair value are reflected in net sales.  Revenue from all marketing and trading activities is reported on a net basis.

Occidental records revenue net of any taxes, such as sales taxes, that are assessed by governmental authorities on Occidental’s customers.

RISKS AND UNCERTAINTIES

The process of preparing consolidated financial statements in conformity with GAAP requires Occidental’s management to make informed estimates and judgments regarding certain types of financial statement balances and disclosures.  Such estimates primarily relate to unsettled transactions and events as of the date of the consolidated financial statements and judgments on the materiality of transactions and balances.  Changes in facts and circumstances or discovery of new information relating to such transactions and events may result in revised estimates and judgments and actual results may differ from estimates upon settlement but generally not by material amounts.  Management believes that these estimates and judgments provide a reasonable basis for the fair presentation of Occidental’s financial statements.

Occidental establishes a valuation allowance against net operating losses and other deferred tax assets to the extent it believes the future benefit from these assets will not be realized in the statutory carryforward periods.  Realization of deferred tax assets, including any net operating loss carryforwards, is dependent upon Occidental generating sufficient future taxable income and reversal of temporary differences in jurisdictions where such assets originate.

The accompanying consolidated financial statements include assets of approximately $12.3 billion as of December 31, 2012, and net sales of approximately $8.8 billion for the year ended December 31, 2012, 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, nationalizations, armed conflict, terrorism, insurgency, civil unrest, security problems, labor unrest, OPEC production restrictions, equipment import restrictions and sanctions, 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 affairs so as to mitigate its exposure to such risks and would seek compensation in the event of nationalization.

Because 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.

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 were approximately $1.0 billion and $3.5 billion at December 31, 2012 and 2011, respectively.

Investments

Available-for-sale securities are recorded at fair value with any unrealized gains or losses included in accumulated other comprehensive income/loss (AOCI).  Trading securities are recorded at fair value with unrealized and realized gains or losses included in net sales.

Inventories

Materials and supplies are valued at weighted-average cost and are reviewed periodically for obsolescence.  Oil, NGL and natural gas inventories are valued at the lower of cost or market.

For the chemical segment, Occidental’s finished goods inventories are valued at the lower of cost or market.  For most of its domestic inventories, other than materials and supplies, the chemical segment uses the last-in, first-out (LIFO) method as it better matches current costs and current revenue.  For other countries, Occidental uses the first-in, first-out method (if the costs of goods are specifically identifiable) or the average-cost method (if the costs of goods are not specifically identifiable).

PROPERTY, PLANT AND EQUIPMENT

Oil and Gas

The carrying value of Occidental’s property, plant and equipment (PP&E) represents the cost incurred to acquire or develop the asset, including any asset retirement obligations and capitalized interest, net of accumulated depreciation, depletion and amortization (DD&A) and net of any impairment charges.  For assets acquired, PP&E cost is based on fair values at the acquisition date.  Asset retirement obligations and interest costs incurred in connection with qualifying capital expenditures are capitalized and amortized over the lives of the related assets.

Occidental uses the successful efforts method to account for its oil and gas properties.  Under this method, Occidental capitalizes costs of acquiring properties, costs of drilling successful exploration wells and development costs.  The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found.  If proved reserves have been found, the costs of exploratory wells remain capitalized.  Otherwise, Occidental charges the costs of the related wells 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 generally expenses the costs of such exploratory wells if a determination of proved reserves has not been made within a 12-month period after drilling is complete.

The following table summarizes the activity of capitalized exploratory well costs for continuing operations for the years ended December 31:

In millions	2012			2011			2010
Balance — Beginning of Year	$	182		$	73		$	51
Additions to capitalized exploratory well costs pending the determination of proved reserves	400			334			112
Reclassifications to property, plant and equipment based on the determination of proved reserves	(407		)	(204		)	(73		)
Capitalized exploratory well costs charged to expense	(77		)	(21		)	(17		)
Balance — End of Year	$	98		$	182		$	73

Occidental expenses annual lease rentals and geological, geophysical and seismic costs as incurred.

Occidental expenses the costs of injectants used in production.

Occidental determines depreciation and depletion of oil and gas producing properties by the unit-of-production method.  It amortizes acquisition costs over total proved reserves, and capitalized development and successful exploration costs  over proved developed reserves.

Proved oil and gas reserves (as defined in the Securities and Exchange Commission’s Regulation S-X, Rule 4-10(a)) are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.  Occidental has no proved oil and gas reserves for which the determination of economic producibility  is subject to the completion of major additional capital expenditures.

A portion of the carrying value of Occidental’s oil and gas properties is attributable to unproved properties.  At December 31, 2012, the net capitalized costs attributable to unproved properties were $4.8 billion.  The unproved amounts are not subject to DD&A until they are classified as proved properties.  As exploration and development work progresses, if reserves on these properties are proved, capitalized costs attributable to the properties become subject to DD&A.  If the exploration and development work were to be unsuccessful, or management’s plans changed with respect to these properties, as a result of economic, operating or contractual conditions, the capitalized costs of the related properties would be expensed.  The timing of any writedowns of these unproved properties, if warranted, depends upon management’s plans, the nature, timing and extent of future exploration and development activities and their results.  Occidental believes its current plans and exploration and development efforts will allow it to realize its unproved property balance.

Additionally, Occidental performs impairment tests with respect to its proved properties generally when prices decline other than temporarily, reserve estimates change significantly or other significant events occur that may impact its ability to realize the recorded asset amounts.  Impairment tests incorporate a number of assumptions involving expectations of future cash flows, which can change significantly over time.  These assumptions include estimates of future product prices, which Occidental bases on forward price curves and, when applicable, contractual prices, estimates of oil and gas reserves and estimates of future expected operating and development costs.

Fluctuations in commodity prices and production and development costs could cause management’s plans to change with respect to unproved properties and could cause the carrying values of proved properties to be unrealizable.  Such circumstances could result in impairments in the carrying values of proved or unproved properties or both.  Any impairment loss would be calculated as the excess of the asset’s net book value over its estimated fair value.

Chemical

Occidental’s chemical assets are depreciated using either the unit-of-production or the straight-line method, based upon the estimated useful lives of the facilities.  The estimated useful lives of Occidental’s chemical assets, which range from three years to 50 years, are also used for impairment tests.  The estimated useful lives 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.  Such expenditures consist of ongoing routine repairs and maintenance, as well as planned major maintenance activities (PMMA).  Ongoing routine repairs and maintenance expenditures are expensed as incurred. PMMA costs are capitalized and amortized over the period until the next planned overhaul.  Additionally, Occidental incurs capital expenditures that extend the remaining useful lives of existing assets, increase their capacity or operating efficiency beyond the original specification or add value through modification for a different use.  These capital expenditures are not considered in the initial determination of the useful lives of these assets at the time they are placed into service.  The resulting revision, if any, of the asset’s estimated useful life is measured and accounted for prospectively.

Without these continued expenditures, the useful lives of these assets could decrease significantly.  Other factors that could change the estimated useful lives of Occidental’s chemical assets include sustained higher or lower product prices, which are particularly affected by both domestic and foreign competition, demand, feedstock costs, energy prices, environmental regulations and technological changes.

Occidental performs impairment tests on its chemical assets whenever events or changes in circumstances lead to a reduction in the estimated useful lives or estimated future cash flows that would indicate that the carrying amount may not be recoverable, or when management’s plans change with respect to those assets.  Any impairment loss would be calculated as the excess of the asset’s net book value over its estimated fair value.

Midstream and Marketing

Occidental’s midstream and marketing PP&E is depreciated over the estimated useful lives of the assets, using either the unit-of-production or straight-line method.

Occidental performs impairment tests on its midstream and marketing 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.  Any impairment loss would be calculated as the excess of the asset’s net book value over its estimated fair value.

FAIR VALUE MEASUREMENTS

Occidental has categorized its assets and liabilities that are measured at fair value in a three-level fair value hierarchy, based on the inputs to the valuation techniques: Level 1 — using quoted prices in active markets for identical assets or liabilities; Level 2 — using observable inputs other than quoted prices for identical assets or liabilities; and Level 3 — using unobservable inputs.  Transfers between levels, if any, are reported at the end of each reporting period.

Fair Values - Recurring

Occidental primarily applies the market approach for recurring fair value measurements, maximizes its use of observable inputs and minimizes its use of unobservable inputs.  Occidental utilizes the mid-point price between bid and ask prices for valuing the majority of its assets and liabilities measured and reported at fair value.  In addition to using market data, Occidental makes assumptions in valuing its assets and liabilities, including assumptions about the risks inherent in the inputs to the valuation technique.  For assets and liabilities carried at fair value, Occidental measures fair value using the following methods:

Ø Commodity derivatives — Occidental values exchange-cleared commodity derivatives using closing prices provided by the exchange as of the balance sheet date.  These derivatives are classified as Level 1.  Over-the-Counter (OTC) bilateral financial commodity contracts, foreign exchange contracts, options and physical commodity forward purchase and sale contracts are generally valued using quotations provided by brokers or industry-standard models that consider various inputs, including quoted forward prices for commodities, time value, volatility factors, credit risk and current market and contractual prices for the underlying instruments, as well as other relevant economic measures.  Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable prices at which transactions are executed in the marketplace.  Occidental classifies these measurements as Level 2.

Ø Embedded commodity derivatives — Occidental values embedded commodity derivatives based on a market approach that considers various assumptions, including quoted forward commodity prices and market yield curves.  The assumptions used include inputs that are observable and unobservable in the marketplace, and the fair value is designated as Level 3 within the valuation hierarchy.

Occidental generally uses an income approach to measure fair value when there is not a market-observable price for an identical or similar asset or liability.  This approach utilizes management’s judgments regarding expectations of projected cash flows, and discounts those cash flows using a risk-adjusted discount rate.

ACCRUED LIABILITIES—CURRENT

Accrued liabilities include accrued payroll, commissions and related expenses of $385 million and $462 million at December 31, 2012 and 2011, respectively.

ENVIRONMENTAL LIABILITIES AND EXPENDITURES

Environmental expenditures that relate to current operations are expensed or capitalized as appropriate.  Occidental records environmental reserves for estimated remediation costs that relate to existing conditions from past operations when environmental remediation efforts are probable and the costs can be reasonably estimated.  In determining the reserves and the range of reasonably possible additional losses, Occidental refers to currently available information, including relevant past experience, remedial objectives, available technologies, applicable laws and regulations and cost-sharing arrangements.  Occidental bases environmental reserves on management’s estimate of the most likely cost to be incurred, using the most cost-effective technology reasonably expected to achieve the remedial objective.  Occidental periodically reviews reserves and adjusts them as new information becomes available.  Occidental records environmental reserves on a discounted basis when it deems the aggregate amount and timing of cash payments to be reliably determinable at the time the reserves are established.  The reserve methodology with respect to discounting for a specific site is not modified once it is established.  The amount of discounted environmental reserves is insignificant.  Occidental generally records reimbursements or recoveries of environmental remediation costs in income when received, or when receipt of recovery is highly probable.  As of December 31, 2012, 2011 and 2010, Occidental did not have any accruals for reimbursements or recoveries.

Many factors could affect Occidental’s future remediation costs and result in adjustments to its environmental reserves and range of reasonably possible additional losses.  The most significant are: (1) cost estimates for remedial activities may be inaccurate; (2) the length of time, type or amount of remediation necessary to achieve the remedial objective may change due to factors such as site conditions, the ability to identify and control contaminant sources or the discovery of additional contamination; (3) a regulatory agency may ultimately reject or modify Occidental’s proposed remedial plan; (4) improved or alternative remediation technologies may change remediation costs; (5) laws and regulations may change remediation requirements or affect cost sharing or allocation of liability; and (6) changes in allocation or cost-sharing arrangements.

Certain sites involve multiple parties with various cost-sharing arrangements, which fall into the following three categories:  (1) environmental proceedings that result in a negotiated or prescribed allocation of remediation costs among Occidental and other alleged potentially responsible parties; (2) oil and gas ventures in which each participant pays its proportionate share of remediation costs reflecting its working interest; or (3) contractual arrangements, typically relating to purchases and sales of properties, in which the parties to the transaction agree to methods of allocating remediation costs.  In these circumstances, Occidental evaluates the financial viability of the other parties with whom it is alleged to be jointly liable, the degree of their commitment to participate and the consequences to Occidental of their failure to participate when estimating Occidental’s ultimate share of liability.  Occidental records reserves at its expected net cost of remedial activities and, based on these factors, believes that it will not be required to assume a share of liability of such other potentially responsible parties in an amount materially above amounts reserved.

In addition to the costs of investigations and cleanup measures, which often take in excess of 10 years at Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA) National Priorities List (NPL) sites, Occidental’s reserves include management’s estimates of the costs to operate and maintain remedial systems.  If remedial systems are modified over time in response to significant changes in site-specific data, laws, regulations, technologies or engineering estimates, Occidental reviews and adjusts its reserves accordingly.

ASSET RETIREMENT OBLIGATIONS

Occidental recognizes the fair value of asset retirement obligations in the period in which a determination is made that a legal obligation exists to dismantle an asset and reclaim or remediate the property at the end of its useful life and the cost of the obligation can be reasonably estimated.  The liability amounts are based on future retirement cost estimates and incorporate many assumptions such as time to abandonment, technological changes, future inflation rates and the risk-adjusted discount rate.  When the liability is initially recorded, Occidental capitalizes the cost by increasing the related PP&E balances.  If the estimated future cost of the asset retirement obligation changes, Occidental records an adjustment to both the asset retirement obligation and PP&E.  Over time, the liability is increased and expense is recognized for accretion, and the capitalized cost is depreciated over the useful life of the asset.

At a certain number of its facilities, Occidental has identified conditional asset retirement obligations that are related mainly to plant decommissioning.  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 $1,212 million and $1,030 million is included in deferred credits and other liabilities - other, with the remaining current portion in accrued liabilities at December 31, 2012 and 2011, respectively.

For the years ended December 31, (in millions)	2012			2011
Beginning balance	$	1,089		$	800
Liabilities incurred - capitalized to PP&E	86			74
Liabilities settled and paid	(58		)	(53		)
Accretion expense	61			48
Acquisitions and other - capitalized to PP&E	50			177
Revisions to estimated cash flows - capitalized to PP&E	38			43
Ending balance	$	1,266		$	1,089

DERIVATIVE INSTRUMENTS

Derivatives are carried at fair value and on a net basis when a legal right of offset exists with the same counterparty.  Occidental applies hedge accounting when transactions meet specified criteria for cash-flow hedge treatment and management elects and documents such treatment.  Otherwise, any fair value gains or losses are recognized in earnings in the current period.  For cash-flow hedges, the gain or loss on the effective portion of the derivative is reported as a component of other comprehensive income (OCI) with an offsetting adjustment to the basis of the item being hedged.  Realized gains or losses from cash-flow hedges, and any ineffective portion, are recorded as a component of net sales in the consolidated statements of income. Ineffectiveness is primarily created by a basis difference between the hedged item and the hedging instrument due to location, quality or grade of the physical commodity underlying the hedging instrument.  Gains and losses from derivative instruments are reported net in the consolidated statements of income. There were no fair value hedges as of and during the years ended December 31, 2012, 2011 and 2010.

A hedge is regarded as highly effective such that it 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 will be offset by 80 to 125 percent of the changes in the fair value or cash flows, respectively, of the hedging instrument.  In the case of hedging a forecast transaction, the transaction must be 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 hedged item matures or is sold or repaid; or when a forecast transaction is no longer deemed probable.

STOCK-BASED INCENTIVE PLANS

Occidental has established several stockholder-approved stock-based incentive plans for certain employees and directors (Plans) that are more fully described in Note 12.  A summary of Occidental’s accounting policy for awards issued under the Plans follows.

For cash- and stock-settled restricted stock units or incentive award shares (RSUs), compensation value is initially measured on the grant date using the quoted market price of Occidental’s common stock.  For total shareholder return incentives (TSRIs), compensation value is initially measured on the grant date using estimated payout levels derived from the Monte Carlo valuation model.  Compensation expense for RSUs 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.  Compensation expense for the cash-settled portion of TSRIs and related dividends is adjusted quarterly for any changes in the number of shares expected to be issued based on the performance criteria using the Monte Carlo valuation model.  In addition, every quarter, compensation expense for the cash-settled portion of RSUs and TSRIs is adjusted for changes in the value of the underlying stock.  All such performance or stock-price-related changes are recognized in periodic compensation expense.  The stock-settled portion of all these awards is expensed using the initially measured compensation value.

EARNINGS PER SHARE

Occidental’s instruments containing rights to nonforfeitable dividends granted in stock-based payment transactions are considered participating securities prior to vesting and, therefore, have been included in the earnings allocations in computing basic and diluted EPS under the two-class method.

Basic EPS was computed by dividing net income attributable to common stock, net of income allocated to participating securities, by the weighted-average number of common shares outstanding during each period, net of treasury shares and including vested but unissued shares and share units. The computation of diluted EPS reflects the additional dilutive effect of stock options and unvested stock awards.

RETIREMENT AND POSTRETIREMENT BENEFIT PLANS

Occidental recognizes the overfunded or underfunded amounts of its defined benefit pension and postretirement plans in its financial statements using a December 31 measurement date.

Occidental determines its defined benefit pension and postretirement benefit plan obligations based on various assumptions and discount rates.  The discount rate assumptions used are meant to reflect the interest rate at which the obligations could effectively be settled on the measurement date.  Occidental estimates the rate of return on assets with regard to current market factors but within the context of historical returns.  Occidental funds and expenses negotiated pension increases for domestic union employees over the terms of the applicable collective bargaining agreements.

Pension and postretirement plan assets are measured at fair value.  Common stock, preferred stock, publicly registered mutual funds, U.S. government securities and corporate bonds are valued using quoted market prices in active markets when available.  When quoted market prices are not available, these investments are valued using pricing models with observable inputs from both active and non-active markets.  Common and collective trusts are valued at the fund units’ net asset value (NAV) provided by the issuer, which represents the quoted price in a non-active market.  Short-term investment funds are valued at the fund units’ NAV provided by the issuer.

SUPPLEMENTAL CASH FLOW INFORMATION

Occidental paid United States federal, state and foreign income taxes for continuing operations of approximately $2.4 billion, $2.9 billion and $2.4 billion during the years ended December 31, 2012, 2011 and 2010, respectively.  Occidental also paid production, property and other taxes of approximately $694 million, $635 million and $510 million during the years ended December 31, 2012, 2011 and 2010, respectively, substantially all of which was in the United States.  Interest paid totaled approximately $190 million, $315 million and $161 million for the years 2012, 2011 and 2010, respectively.  The 2011 interest paid included $154 million of debt extinguishment premiums.

FOREIGN CURRENCY TRANSACTIONS

The functional currency applicable to all of Occidental’s foreign oil and gas operations is the United States dollar since cash flows are denominated principally in United States dollars.  In Occidental’s other operations, Occidental’s use of non-United States dollar functional currencies was not material for all years presented.  The effect of exchange rates on transactions in foreign currencies is included in periodic income.  Occidental reports the exchange rate differences arising from translating foreign currency denominated balance sheet accounts to the United States dollar as of the reporting date in other comprehensive income.  Exchange-rate gains and losses for continuing operations were not material for all years presented.

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DOMESTIC AND FOREIGN INCOME TAXES (Details) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Domestic and foreign components of income from continuing operations before domestic and foreign income taxes and net of noncontrolling interest
Income from continuing operations net of noncontrolling interest before income taxes, Domestic	$ 2,117,000,000	$ 4,806,000,000	$ 3,295,000,000
Income from continuing operations net of noncontrolling interest before income taxes, Foreign	5,636,000,000	6,035,000,000	4,269,000,000
Income from continuing operations net of noncontrolling interest before income taxes, Total	7,753,000,000	10,841,000,000	7,564,000,000
Pre-tax charges for the impairment of domestic gas assets and related items	1,751,000,000		275,000,000
Provisions (credits) for domestic and foreign income taxes on continuing operations
Current United States Federal tax expense (benefit)	(401,000,000)	320,000,000	614,000,000
Current State and Local tax expense (benefit)	8,000,000	88,000,000	79,000,000
Current Foreign tax expense (benefit)	2,383,000,000	2,357,000,000	1,896,000,000
Current Total tax expense (benefit)	1,990,000,000	2,765,000,000	2,589,000,000
Deferred United States Federal tax expense (benefit)	1,046,000,000	1,340,000,000	390,000,000
Deferred State and Local tax expense (benefit)	41,000,000	47,000,000	4,000,000
Deferred Foreign tax expense (benefit)	41,000,000	49,000,000	12,000,000
Deferred Total tax expense (benefit)	1,128,000,000	1,436,000,000	406,000,000
United States Federal Total tax expense (benefit)	645,000,000	1,660,000,000	1,004,000,000
State and Local Total tax expense (benefit)	49,000,000	135,000,000	83,000,000
Foreign Total tax expense (benefit)	2,424,000,000	2,406,000,000	1,908,000,000
Total tax expense (benefit)	3,118,000,000	4,201,000,000	2,995,000,000
Reconciliation of the United States statutory federal income tax rate to Occidental's effective tax rate on income from continuing operations
United States federal statutory tax rate (as a percent)	35.00%	35.00%	35.00%
Operations outside the United States (as a percent)	5.00%	4.00%	5.00%
State income taxes, net of federal benefit (as a percent)	1.00%	1.00%	1.00%
Other (as a percent)	(1.00%)	(1.00%)	(1.00%)
Worldwide effective tax rate (as a percent)	40.00%	39.00%	40.00%
Deferred Tax Assets and Liabilities
Deferred Tax Assets, environmental reserves	126,000,000	131,000,000
Deferred Tax Assets, postretirement benefit accruals	413,000,000	410,000,000
Deferred Tax Assets, deferred compensation and benefits	278,000,000	286,000,000
Deferred Tax Assets, asset retirement obligations	367,000,000	318,000,000
Deferred Tax Assets, foreign tax credit carryforwards	1,277,000,000	1,240,000,000
Deferred Tax Assets, Other tax credit carryforwards	195,000,000
Deferred tax Assets, federal benefit of state income taxes	89,000,000	104,000,000
Deferred Tax Assets, all other	334,000,000	374,000,000
Deferred Tax Assets, subtotal	3,079,000,000	2,863,000,000
Deferred Tax Assets, valuation allowance	(1,040,000,000)	(1,003,000,000)
Deferred Tax Assets, total deferred taxes	2,039,000,000	1,860,000,000
Deferred Tax Liabilities, property, plant and equipment differences	7,316,000,000	6,039,000,000
Deferred Tax Liabilities, equity investments, partnerships and foreign subsidiaries	351,000,000	351,000,000
Deferred Tax Liabilities, all other	161,000,000	116,000,000
Deferred Tax Liabilities, total deferred taxes	7,828,000,000	6,506,000,000
Deferred tax assets, current	250,000,000	200,000,000
Unremitted earnings of certain consolidated foreign subsidiaries	8,100,000,000
Deferred tax liability not recognized, indefinitely reinvested foreign earnings	116,000,000
Discontinued operations income tax charges (benefits)	7,000,000	86,000,000	(26,000,000)
Credit to additional paid-in capital, excess tax benefit from the exercise of certain stock-based compensation awards	8,000,000	14,000,000	22,000,000
Unrecognized tax benefits included in deferred credits and other liabilities that would affect effective tax rate	76,000,000
Reconciliation of unrecognized tax benefits
Balance, at beginning of period	67,000,000	38,000,000
Additions based on tax positions related to the current year	16,000,000	44,000,000
Reductions based on tax positions related to prior years and settlements	(7,000,000)	(15,000,000)
Balance, at end of period	$ 76,000,000	$ 67,000,000	$ 38,000,000

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

12 Months Ended

Dec. 31, 2012

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Consolidation policy

PRINCIPLES OF CONSOLIDATION

The consolidated financial statements have been prepared in conformity with United States generally accepted accounting principles (GAAP) and include the accounts of OPC, its subsidiaries and its undivided interests in oil and gas exploration and production ventures.  Occidental accounts for its share of oil and gas exploration and production ventures, in which it has a direct working interest, 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.

Certain financial statements, notes and supplementary data for prior years have been reclassified to conform to the 2012 presentation.

Investments in unconsolidated entities policy

INVESTMENTS IN UNCONSOLIDATED ENTITIES

Occidental’s percentage interest in the underlying net assets of affiliates as to which it exercises significant influence without having a controlling interest (excluding oil and gas ventures in which Occidental holds an undivided interest) 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 may have occurred.  The amount of impairment, if any, is based on quoted market prices, when available, or other valuation techniques, including discounted cash flows.

Revenue recognition policy

REVENUE RECOGNITION

Revenue is recognized from oil and gas production when title has passed to the customer, which occurs when the product is shipped.  In international locations where oil is shipped by tanker, title passes when the tanker is loaded or product is received by the customer, depending on the shipping terms.  This process occasionally causes a difference between actual production in a reporting period and sales volumes that have been recognized as revenue.

Revenue from chemical product sales is recognized when the product is shipped and title has passed to the customer.  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.

Revenue from marketing and trading activities is recognized on net settled transactions upon completion of contract terms and, for physical deliveries, upon title transfer.  For unsettled transactions, contracts are recorded at fair value and changes in fair value are reflected in net sales.  Revenue from all marketing and trading activities is reported on a net basis.

Occidental records revenue net of any taxes, such as sales taxes, that are assessed by governmental authorities on Occidental’s customers.

Deferred tax asset valuation allowance policy

Occidental establishes a valuation allowance against net operating losses and other deferred tax assets to the extent it believes the future benefit from these assets will not be realized in the statutory carryforward periods.  Realization of deferred tax assets, including any net operating loss carryforwards, is dependent upon Occidental generating sufficient future taxable income and reversal of temporary differences in jurisdictions where such assets originate.

Cash and cash equivalents policy

CASH AND CASH EQUIVALENTS

Cash equivalents are short-term, highly liquid investments that are readily convertible to cash.  Cash equivalents were approximately $1.0 billion and $3.5 billion at December 31, 2012 and 2011, respectively.

Available-for-sale securities and trading securities policy

Investments

Available-for-sale securities are recorded at fair value with any unrealized gains or losses included in accumulated other comprehensive income/loss (AOCI).  Trading securities are recorded at fair value with unrealized and realized gains or losses included in net sales.

Inventory policy

Inventories

Materials and supplies are valued at weighted-average cost and are reviewed periodically for obsolescence.  Oil, NGL and natural gas inventories are valued at the lower of cost or market.

For the chemical segment, Occidental’s finished goods inventories are valued at the lower of cost or market.  For most of its domestic inventories, other than materials and supplies, the chemical segment uses the last-in, first-out (LIFO) method as it better matches current costs and current revenue.  For other countries, Occidental uses the first-in, first-out method (if the costs of goods are specifically identifiable) or the average-cost method (if the costs of goods are not specifically identifiable).

Property, plant and equipment policy

PROPERTY, PLANT AND EQUIPMENT

Oil and Gas

The carrying value of Occidental’s property, plant and equipment (PP&E) represents the cost incurred to acquire or develop the asset, including any asset retirement obligations and capitalized interest, net of accumulated depreciation, depletion and amortization (DD&A) and net of any impairment charges.  For assets acquired, PP&E cost is based on fair values at the acquisition date.  Asset retirement obligations and interest costs incurred in connection with qualifying capital expenditures are capitalized and amortized over the lives of the related assets.

Occidental uses the successful efforts method to account for its oil and gas properties.  Under this method, Occidental capitalizes costs of acquiring properties, costs of drilling successful exploration wells and development costs.  The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found.  If proved reserves have been found, the costs of exploratory wells remain capitalized.  Otherwise, Occidental charges the costs of the related wells 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 generally expenses the costs of such exploratory wells if a determination of proved reserves has not been made within a 12-month period after drilling is complete.

The following table summarizes the activity of capitalized exploratory well costs for continuing operations for the years ended December 31:

In millions	2012			2011			2010
Balance — Beginning of Year	$	182		$	73		$	51
Additions to capitalized exploratory well costs pending the determination of proved reserves	400			334			112
Reclassifications to property, plant and equipment based on the determination of proved reserves	(407		)	(204		)	(73		)
Capitalized exploratory well costs charged to expense	(77		)	(21		)	(17		)
Balance — End of Year	$	98		$	182		$	73

Occidental expenses annual lease rentals and geological, geophysical and seismic costs as incurred.

Occidental expenses the costs of injectants used in production.

Occidental determines depreciation and depletion of oil and gas producing properties by the unit-of-production method.  It amortizes acquisition costs over total proved reserves, and capitalized development and successful exploration costs  over proved developed reserves.

Proved oil and gas reserves (as defined in the Securities and Exchange Commission’s Regulation S-X, Rule 4-10(a)) are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.  Occidental has no proved oil and gas reserves for which the determination of economic producibility  is subject to the completion of major additional capital expenditures.

A portion of the carrying value of Occidental’s oil and gas properties is attributable to unproved properties.  At December 31, 2012, the net capitalized costs attributable to unproved properties were $4.8 billion.  The unproved amounts are not subject to DD&A until they are classified as proved properties.  As exploration and development work progresses, if reserves on these properties are proved, capitalized costs attributable to the properties become subject to DD&A.  If the exploration and development work were to be unsuccessful, or management’s plans changed with respect to these properties, as a result of economic, operating or contractual conditions, the capitalized costs of the related properties would be expensed.  The timing of any writedowns of these unproved properties, if warranted, depends upon management’s plans, the nature, timing and extent of future exploration and development activities and their results.  Occidental believes its current plans and exploration and development efforts will allow it to realize its unproved property balance.

Additionally, Occidental performs impairment tests with respect to its proved properties generally when prices decline other than temporarily, reserve estimates change significantly or other significant events occur that may impact its ability to realize the recorded asset amounts.  Impairment tests incorporate a number of assumptions involving expectations of future cash flows, which can change significantly over time.  These assumptions include estimates of future product prices, which Occidental bases on forward price curves and, when applicable, contractual prices, estimates of oil and gas reserves and estimates of future expected operating and development costs.

Fluctuations in commodity prices and production and development costs could cause management’s plans to change with respect to unproved properties and could cause the carrying values of proved properties to be unrealizable.  Such circumstances could result in impairments in the carrying values of proved or unproved properties or both.  Any impairment loss would be calculated as the excess of the asset’s net book value over its estimated fair value.

Chemical

Occidental’s chemical assets are depreciated using either the unit-of-production or the straight-line method, based upon the estimated useful lives of the facilities.  The estimated useful lives of Occidental’s chemical assets, which range from three years to 50 years, are also used for impairment tests.  The estimated useful lives 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.  Such expenditures consist of ongoing routine repairs and maintenance, as well as planned major maintenance activities (PMMA).  Ongoing routine repairs and maintenance expenditures are expensed as incurred. PMMA costs are capitalized and amortized over the period until the next planned overhaul.  Additionally, Occidental incurs capital expenditures that extend the remaining useful lives of existing assets, increase their capacity or operating efficiency beyond the original specification or add value through modification for a different use.  These capital expenditures are not considered in the initial determination of the useful lives of these assets at the time they are placed into service.  The resulting revision, if any, of the asset’s estimated useful life is measured and accounted for prospectively.

Without these continued expenditures, the useful lives of these assets could decrease significantly.  Other factors that could change the estimated useful lives of Occidental’s chemical assets include sustained higher or lower product prices, which are particularly affected by both domestic and foreign competition, demand, feedstock costs, energy prices, environmental regulations and technological changes.

Occidental performs impairment tests on its chemical assets whenever events or changes in circumstances lead to a reduction in the estimated useful lives or estimated future cash flows that would indicate that the carrying amount may not be recoverable, or when management’s plans change with respect to those assets.  Any impairment loss would be calculated as the excess of the asset’s net book value over its estimated fair value.

Midstream and Marketing

Occidental’s midstream and marketing PP&E is depreciated over the estimated useful lives of the assets, using either the unit-of-production or straight-line method.

Occidental performs impairment tests on its midstream and marketing 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.  Any impairment loss would be calculated as the excess of the asset’s net book value over its estimated fair value.

Fair value policy

FAIR VALUE MEASUREMENTS

Occidental has categorized its assets and liabilities that are measured at fair value in a three-level fair value hierarchy, based on the inputs to the valuation techniques: Level 1 — using quoted prices in active markets for identical assets or liabilities; Level 2 — using observable inputs other than quoted prices for identical assets or liabilities; and Level 3 — using unobservable inputs.  Transfers between levels, if any, are reported at the end of each reporting period.

Fair Values - Recurring

Occidental primarily applies the market approach for recurring fair value measurements, maximizes its use of observable inputs and minimizes its use of unobservable inputs.  Occidental utilizes the mid-point price between bid and ask prices for valuing the majority of its assets and liabilities measured and reported at fair value.  In addition to using market data, Occidental makes assumptions in valuing its assets and liabilities, including assumptions about the risks inherent in the inputs to the valuation technique.  For assets and liabilities carried at fair value, Occidental measures fair value using the following methods:

Ø Commodity derivatives — Occidental values exchange-cleared commodity derivatives using closing prices provided by the exchange as of the balance sheet date.  These derivatives are classified as Level 1.  Over-the-Counter (OTC) bilateral financial commodity contracts, foreign exchange contracts, options and physical commodity forward purchase and sale contracts are generally valued using quotations provided by brokers or industry-standard models that consider various inputs, including quoted forward prices for commodities, time value, volatility factors, credit risk and current market and contractual prices for the underlying instruments, as well as other relevant economic measures.  Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable prices at which transactions are executed in the marketplace.  Occidental classifies these measurements as Level 2.

Ø Embedded commodity derivatives — Occidental values embedded commodity derivatives based on a market approach that considers various assumptions, including quoted forward commodity prices and market yield curves.  The assumptions used include inputs that are observable and unobservable in the marketplace, and the fair value is designated as Level 3 within the valuation hierarchy.

Occidental generally uses an income approach to measure fair value when there is not a market-observable price for an identical or similar asset or liability.  This approach utilizes management’s judgments regarding expectations of projected cash flows, and discounts those cash flows using a risk-adjusted discount rate.

Environmental liabilities and expenditures policy

ENVIRONMENTAL LIABILITIES AND EXPENDITURES

Environmental expenditures that relate to current operations are expensed or capitalized as appropriate.  Occidental records environmental reserves for estimated remediation costs that relate to existing conditions from past operations when environmental remediation efforts are probable and the costs can be reasonably estimated.  In determining the reserves and the range of reasonably possible additional losses, Occidental refers to currently available information, including relevant past experience, remedial objectives, available technologies, applicable laws and regulations and cost-sharing arrangements.  Occidental bases environmental reserves on management’s estimate of the most likely cost to be incurred, using the most cost-effective technology reasonably expected to achieve the remedial objective.  Occidental periodically reviews reserves and adjusts them as new information becomes available.  Occidental records environmental reserves on a discounted basis when it deems the aggregate amount and timing of cash payments to be reliably determinable at the time the reserves are established.  The reserve methodology with respect to discounting for a specific site is not modified once it is established.  The amount of discounted environmental reserves is insignificant.  Occidental generally records reimbursements or recoveries of environmental remediation costs in income when received, or when receipt of recovery is highly probable.  As of December 31, 2012, 2011 and 2010, Occidental did not have any accruals for reimbursements or recoveries.

Many factors could affect Occidental’s future remediation costs and result in adjustments to its environmental reserves and range of reasonably possible additional losses.  The most significant are: (1) cost estimates for remedial activities may be inaccurate; (2) the length of time, type or amount of remediation necessary to achieve the remedial objective may change due to factors such as site conditions, the ability to identify and control contaminant sources or the discovery of additional contamination; (3) a regulatory agency may ultimately reject or modify Occidental’s proposed remedial plan; (4) improved or alternative remediation technologies may change remediation costs; (5) laws and regulations may change remediation requirements or affect cost sharing or allocation of liability; and (6) changes in allocation or cost-sharing arrangements.

Certain sites involve multiple parties with various cost-sharing arrangements, which fall into the following three categories:  (1) environmental proceedings that result in a negotiated or prescribed allocation of remediation costs among Occidental and other alleged potentially responsible parties; (2) oil and gas ventures in which each participant pays its proportionate share of remediation costs reflecting its working interest; or (3) contractual arrangements, typically relating to purchases and sales of properties, in which the parties to the transaction agree to methods of allocating remediation costs.  In these circumstances, Occidental evaluates the financial viability of the other parties with whom it is alleged to be jointly liable, the degree of their commitment to participate and the consequences to Occidental of their failure to participate when estimating Occidental’s ultimate share of liability.  Occidental records reserves at its expected net cost of remedial activities and, based on these factors, believes that it will not be required to assume a share of liability of such other potentially responsible parties in an amount materially above amounts reserved.

In addition to the costs of investigations and cleanup measures, which often take in excess of 10 years at Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA) National Priorities List (NPL) sites, Occidental’s reserves include management’s estimates of the costs to operate and maintain remedial systems.  If remedial systems are modified over time in response to significant changes in site-specific data, laws, regulations, technologies or engineering estimates, Occidental reviews and adjusts its reserves accordingly.

Asset retirement obligations policy

ASSET RETIREMENT OBLIGATIONS

Occidental recognizes the fair value of asset retirement obligations in the period in which a determination is made that a legal obligation exists to dismantle an asset and reclaim or remediate the property at the end of its useful life and the cost of the obligation can be reasonably estimated.  The liability amounts are based on future retirement cost estimates and incorporate many assumptions such as time to abandonment, technological changes, future inflation rates and the risk-adjusted discount rate.  When the liability is initially recorded, Occidental capitalizes the cost by increasing the related PP&E balances.  If the estimated future cost of the asset retirement obligation changes, Occidental records an adjustment to both the asset retirement obligation and PP&E.  Over time, the liability is increased and expense is recognized for accretion, and the capitalized cost is depreciated over the useful life of the asset.

At a certain number of its facilities, Occidental has identified conditional asset retirement obligations that are related mainly to plant decommissioning.  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 $1,212 million and $1,030 million is included in deferred credits and other liabilities - other, with the remaining current portion in accrued liabilities at December 31, 2012 and 2011, respectively.

For the years ended December 31, (in millions)	2012			2011
Beginning balance	$	1,089		$	800
Liabilities incurred - capitalized to PP&E	86			74
Liabilities settled and paid	(58		)	(53		)
Accretion expense	61			48
Acquisitions and other - capitalized to PP&E	50			177
Revisions to estimated cash flows - capitalized to PP&E	38			43
Ending balance	$	1,266		$	1,089

Derivatives Policy

DERIVATIVE INSTRUMENTS

Derivatives are carried at fair value and on a net basis when a legal right of offset exists with the same counterparty.  Occidental applies hedge accounting when transactions meet specified criteria for cash-flow hedge treatment and management elects and documents such treatment.  Otherwise, any fair value gains or losses are recognized in earnings in the current period.  For cash-flow hedges, the gain or loss on the effective portion of the derivative is reported as a component of other comprehensive income (OCI) with an offsetting adjustment to the basis of the item being hedged.  Realized gains or losses from cash-flow hedges, and any ineffective portion, are recorded as a component of net sales in the consolidated statements of income. Ineffectiveness is primarily created by a basis difference between the hedged item and the hedging instrument due to location, quality or grade of the physical commodity underlying the hedging instrument.  Gains and losses from derivative instruments are reported net in the consolidated statements of income. There were no fair value hedges as of and during the years ended December 31, 2012, 2011 and 2010.

A hedge is regarded as highly effective such that it 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 will be offset by 80 to 125 percent of the changes in the fair value or cash flows, respectively, of the hedging instrument.  In the case of hedging a forecast transaction, the transaction must be 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 hedged item matures or is sold or repaid; or when a forecast transaction is no longer deemed probable.

Stock-based compensation and pension and postretirement benefits policy

STOCK-BASED INCENTIVE PLANS

Occidental has established several stockholder-approved stock-based incentive plans for certain employees and directors (Plans) that are more fully described in Note 12.  A summary of Occidental’s accounting policy for awards issued under the Plans follows.

For cash- and stock-settled restricted stock units or incentive award shares (RSUs), compensation value is initially measured on the grant date using the quoted market price of Occidental’s common stock.  For total shareholder return incentives (TSRIs), compensation value is initially measured on the grant date using estimated payout levels derived from the Monte Carlo valuation model.  Compensation expense for RSUs 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.  Compensation expense for the cash-settled portion of TSRIs and related dividends is adjusted quarterly for any changes in the number of shares expected to be issued based on the performance criteria using the Monte Carlo valuation model.  In addition, every quarter, compensation expense for the cash-settled portion of RSUs and TSRIs is adjusted for changes in the value of the underlying stock.  All such performance or stock-price-related changes are recognized in periodic compensation expense.  The stock-settled portion of all these awards is expensed using the initially measured compensation value.

RETIREMENT AND POSTRETIREMENT BENEFIT PLANS

Occidental recognizes the overfunded or underfunded amounts of its defined benefit pension and postretirement plans in its financial statements using a December 31 measurement date.

Occidental determines its defined benefit pension and postretirement benefit plan obligations based on various assumptions and discount rates.  The discount rate assumptions used are meant to reflect the interest rate at which the obligations could effectively be settled on the measurement date.  Occidental estimates the rate of return on assets with regard to current market factors but within the context of historical returns.  Occidental funds and expenses negotiated pension increases for domestic union employees over the terms of the applicable collective bargaining agreements.

Pension and postretirement plan assets are measured at fair value.  Common stock, preferred stock, publicly registered mutual funds, U.S. government securities and corporate bonds are valued using quoted market prices in active markets when available.  When quoted market prices are not available, these investments are valued using pricing models with observable inputs from both active and non-active markets.  Common and collective trusts are valued at the fund units’ net asset value (NAV) provided by the issuer, which represents the quoted price in a non-active market.  Short-term investment funds are valued at the fund units’ NAV provided by the issuer.

Earnings per share policy

EARNINGS PER SHARE

Occidental’s instruments containing rights to nonforfeitable dividends granted in stock-based payment transactions are considered participating securities prior to vesting and, therefore, have been included in the earnings allocations in computing basic and diluted EPS under the two-class method.

Basic EPS was computed by dividing net income attributable to common stock, net of income allocated to participating securities, by the weighted-average number of common shares outstanding during each period, net of treasury shares and including vested but unissued shares and share units. The computation of diluted EPS reflects the additional dilutive effect of stock options and unvested stock awards.

Foreign currency transactions and translations policy

FOREIGN CURRENCY TRANSACTIONS

The functional currency applicable to all of Occidental’s foreign oil and gas operations is the United States dollar since cash flows are denominated principally in United States dollars.  In Occidental’s other operations, Occidental’s use of non-United States dollar functional currencies was not material for all years presented.  The effect of exchange rates on transactions in foreign currencies is included in periodic income.  Occidental reports the exchange rate differences arising from translating foreign currency denominated balance sheet accounts to the United States dollar as of the reporting date in other comprehensive income.  Exchange-rate gains and losses for continuing operations were not material for all years presented.

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INVESTMENTS AND RELATED-PARTY TRANSACTIONS (Tables)

12 Months Ended

Dec. 31, 2012

INVESTMENTS AND RELATED-PARTY TRANSACTIONS

Summarized financial information of equity-method investments

For the years ended December 31, (in millions)	2012		2011		2010
Revenues	$	2,667	$	2,439	$	1,759
Costs and expenses	2,310		2,046		1,482
Net income	$	357	$	393	$	277
As of December 31, (in millions)	2012		2011
Current assets	$	2,065	$	2,230
Non-current assets	$	5,104	$	4,381
Current liabilities	$	1,774	$	1,532
Long-term debt	$	2,250	$	2,305
Other non-current liabilities	$	241	$	168
Stockholders’ equity	$	2,904	$	2,606

Related-party transactions

December 31, (in millions)	2012		2011		2010
Purchases (a)	$	8	$	10	$	153
Sales (b)	$	419	$	392	$	440
Services	$	17	$	10	$	2
Advances and amounts due from	$	25	$	32	$	135
Amounts due to	$	129	$	21	$	383

(a) In 2010, purchases from EHP accounted for 90 percent of total purchases.

(b) In 2012, 2011 and 2010, sales of Occidental-produced oil and NGLs to Plains Pipeline accounted for 80 percent, 76 percent and 50 percent of these totals, respectively.  Additionally, Occidental conducts marketing and trading activities with Plains Pipeline for oil and NGLs.  These transactions are reported in Occidental’s income statement on a net margin basis.  The sales amounts above include the net margins on such transactions, which were negligible.  In 2012 and 2011, sales to Dolphin Energy accounted for 12 percent and 16 percent, of total sales, respectively.  In 2010, sales to EHP and Dolphin Energy accounted for 44 percent of total sales.

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STOCKHOLDERS' EQUITY

12 Months Ended

Dec. 31, 2012

STOCKHOLDERS' EQUITY

STOCKHOLDERS' EQUITY

NOTE 11 STOCKHOLDERS’ EQUITY

The following is a summary of common stock issuances:

Shares in thousands	Common Stock
Balance, December 31, 2009	883,643
Issued	967
Options exercised and other, net	665
Balance, December 31, 2010	885,275
Issued	1,302
Options exercised and other, net	232
Balance, December 31, 2011	886,809
Issued	1,746
Options exercised and other, net	246
Balance, December 31, 2012	888,801

TREASURY STOCK

Occidental has had a 95 million share repurchase program authorized since 2008; however, the program does not obligate Occidental to acquire any specific number of shares and may be discontinued at any time.  In 2012 and 2011, respectively, Occidental purchased 7.2 million and 2.7 million shares under the program at an average cost of $77.98 and $77.12 per share.

Additionally, Occidental purchased shares from the trustee of its defined contribution savings plan during the years ended December 31, 2012, 2011 and 2010.

As of December 31, 2012, 2011 and 2010, treasury stock shares numbered 83.3 million, 75.8 million and 72.5 million, respectively.

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, 2012, 2011 and 2010, Occidental had no outstanding shares of preferred stock.

EARNINGS PER SHARE

The following table presents the calculation of basic and diluted EPS for the years ended December 31:

In millions, except per-share amounts	2012			2011			2010
Basic EPS
Income from continuing operations	$	4,635	(a)	$	6,640		$	4,641
Less: Income from continuing operations attributable to noncontrolling interest	—			—			(72		)
Income from continuing operations attributable to common stock	4,635			6,640			4,569
Discontinued operations, net	(37		)	131			(39		)
Net income attributable to common stock	4,598			6,771			4,530
Less: Net income allocated to participating securities	(8		)	(11		)	(6		)
Net income attributable to common stock, net of participating securities	$	4,590		$	6,760		$	4,524
Weighted average number of basic shares	809.3			812.1			812.5
Basic EPS	$	5.67		$	8.32		$	5.57
Diluted EPS
Net income attributable to common stock, net of participating securities	$	4,590		$	6,760		$	4,524
Weighted average number of basic shares	809.3			812.1			812.5
Dilutive effect of potentially dilutive securities	0.7			0.8			1.3
Total diluted weighted average common shares	810.0			812.9			813.8
Diluted EPS	$	5.67		$	8.32		$	5.56

(a) Includes after-tax charges of $1.1 billion for the impairment of domestic gas assets and related items.

ACCUMULATED OTHER COMPREHENSIVE LOSS

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

Balance at December 31, (in millions)	2012			2011
Foreign currency translation adjustments	$	(34	)	$	(9	)
Unrealized gains (losses) on derivatives	(7		)	1
Pension and post-retirement adjustments (a)	(461		)	(475		)
Total	$	(502	)	$	(483	)

(a) See Note 13 for further information.