Edgar Filing: OCCIDENTAL PETROLEUM CORP /DE/

form10k-2011.htm

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

R Annual 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, 2011		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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. 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 $83.2 billion, computed by reference to the closing price on the New York Stock Exchange composite tape of $104.04 per share of Common Stock on June 30, 2011. 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, 2012, there were 811,055,632 shares of Common Stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s definitive Proxy Statement, filed in connection with its May 4, 2012 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
	Executive Officers	7
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	10
Item 7 and 7A	Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A)	10
	Strategy	10
	Oil and Gas Segment	13
	Chemical Segment	18
	Midstream, Marketing and Other Segment	19
	Segment Results of Operations	20
	Significant Items Affecting Earnings	22
	Taxes	22
	Consolidated Results of Operations	22
	Consolidated Analysis of Financial Position	23
	Liquidity and Capital Resources	24
	Off-Balance-Sheet Arrangements	26
	Contractual Obligations	26
	Lawsuits, Claims and Other Contingencies	26
	Environmental Liabilities and Expenditures	27
	Foreign Investments	28
	Critical Accounting Policies and Estimates	28
	Significant Accounting and Disclosure Changes	31
	Derivative Activities and Market Risk	31
	Safe Harbor Discussion Regarding Outlook and Other Forward-Looking Data	33
Item 8	Financial Statements and Supplementary Data	34
	Management's Annual Assessment of and Report on Internal Control Over Financial Reporting	34
	Report of Independent Registered Public Accounting Firm on Consolidated Financial Statements	34
	Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting	35
	Consolidated Balance Sheets	36
	Consolidated Statements of Income	38
	Consolidated Statements of Comprehensive Income	39
	Consolidated Statements of Stockholders' Equity	39
	Consolidated Statements of Cash Flows	40
	Notes to Consolidated Financial Statements	41
	Quarterly Financial Data (Unaudited)	69
	Supplemental Oil and Gas Information (Unaudited)	71
	Financial Statement Schedule:
	Schedule II – Valuation and Qualifying Accounts	84
Item 9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	85
Item 9A	Controls and Procedures	85
	Disclosure Controls and Procedures	85
Part III
Item 10	Directors, Executive Officers and Corporate Governance	85
Item 11	Executive Compensation	85
Item 12	Security Ownership of Certain Beneficial Owners and Management	85
Item 13	Certain Relationships and Related Transactions and Director Independence	85
Item 14	Principal Accountant Fees and Services	85

Part IV
Item 15	Exhibits and Financial Statement Schedules	86

Part I

Items 1 And 2 Business and Properties

In this report, "Occidental" refers to 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, treats, processes, transports, stores, purchases and markets oil, condensate, NGLs, natural gas, carbon dioxide (CO2) and power. It also trades around its assets, including pipelines and storage capacity, and trades oil, NGLs, gas and other commodities.

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, Montana, New Mexico, North Dakota, Oklahoma, Texas, Utah and West Virginia. International operations are located in Bahrain, Bolivia, Colombia, Iraq, Libya, Oman, Qatar, the United Arab Emirates (UAE) and Yemen. Occidental sold its Argentine operations in February 2011 and has classified them as discontinued operations on a retrospective application basis.

Proved Reserves and Sales Volumes

The table below shows Occidental’s total oil, NGLs and natural gas proved reserves and sales volumes in 2011, 2010 and 2009. 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; barrels of oil equivalent (BOE) in millions of barrels of oil equivalent

	2011						2010						2009
Proved Reserves	Oil		NGLs	Gas	BOE	(a)	Oil		NGLs	Gas	BOE	(a)	Oil		NGLs	Gas	BOE	(a)
United States	1,526		225	3,365	2,313		1,460		237	3,034	2,203		1,385		221	2,799	2,072
International (b)	482	(c)	55	1,958	863	(c)	552	(c)	61	2,104	964	(c)	589	(d)	68	2,228	1,028	(d)
Total	2,008		280	5,323	3,176	(e)	2,012		298	5,138	3,167	(e)	1,974		289	5,027	3,100	(e)
Sales Volumes
United States	84		25	285	156		80		19	247	140		81		18	232	137
International (b)	80		4	162	111		83	(d)	5	172	117	(d)	65	(d)	4	95	85	(d)
Total	164		29	447	267		163		24	419	257		146		22	327	222

(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.
(b)	Excludes volumes from the Argentine operations sold in February 2011 and classified as discontinued operations.
(c)	Excludes 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.
(d)	Includes the noncontrolling interest in a Colombian subsidiary.
(e)	Stated on a net basis after applicable royalties. Includes proved reserves related to production-sharing contracts (PSCs) and other similar economic arrangements of 1.0 billion BOE in 2011, 1.1 billion BOE in 2010 and 1.1 billion BOE in 2009.

Competition and Sales and Marketing

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 strategic acquisitions and enhanced oil recovery projects in mature and underdeveloped fields. Occidental also competes to develop and produce its worldwide oil and gas reserves cost-effectively and obtain the required labor and services.

Chemical Operations

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 and has interests in a Brazilian joint venture.

In 2011, OxyChem announced plans to build a 182,500-ton-per-year membrane chlor-alkali plant in Tennessee, which it expects to begin operating in 2013.

OxyChem competes with numerous other domestic and foreign chemical producers. For every product it manufactures and markets, OxyChem’s market position is first or second in the United States and first, second or third in the world. 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.

Midstream, Marketing and Other Operations

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

Location	Description	Capacity
Gas Plants
California, Colorado and Permian Basin	Occidental-operated and third-party-operated gas gathering, treating, compression and processing systems, and CO2 processing	2.6 billion cubic feet per day
Pipelines
Permian Basin 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
Colorado, New Mexico and Texas - CO2 fields and pipelines	CO2 fields and pipeline systems transporting CO2 to oil and gas producing locations	1.945 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	16,000 miles of pipeline and gathering systems (b) Storage for 100 million barrels of oil and other petroleum products and 76 billion cubic feet of natural gas (b)
Marketing and Trading
Texas, Connecticut, United Kingdom, Singapore and other	Trades around its assets and purchases, markets and trades oil, 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)	Capacity requires additional gas compression and customer contracts.
(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 11,300 people at December 31, 2011, 8,000 of whom were located in the United States. Occidental employed approximately 7,200 people in the oil and gas and midstream and marketing segments and 3,000 people in the chemical segment. An additional 1,100 people were employed in administrative and headquarters functions. Approximately 800 U.S.-based employees and 200 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 web site is not part of this report.

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 gas.

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 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, reserves 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 are: (i) 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 labor and employment, taxes, royalty rates, permitted production rates, drilling, manufacturing or production processes (including hydraulic fracturing), 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 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 product prices; (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.

Calculations of oil and gas reserves depend on estimates concerning reservoir characteristics and recoverability, including production decline rates and operating performance, as well as capital and operating costs. If Occidental were required to make unanticipated significant negative reserve revisions, its results of operations and stock price could be adversely affected.

Concerns about climate change may affect Occidental’s operations.

There is an ongoing effort to assess and quantify the effects of climate change and the potential human influences on climate. The U.S. federal government and the states of California and New Mexico 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. California’s cap-and-trade program is moving into the implementation phase. 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 delays in development projects, increases in costs and taxes and reductions in the 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 or cyber 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.

Other risk factors.

Additional discussion of risks related to oil and gas reserves estimation processes, price and demand, litigation, environmental matters, foreign operations, impairments, derivatives and market risks 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," and "— Derivative Activities and Market Risk."

Item 1B Unresolved Staff Comments

Occidental has no unresolved SEC staff comments that have been outstanding more than 180 days at December 31, 2011.

Item 3 Legal Proceedings

For information regarding 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.

Executive Officers

The current term of employment of each executive officer of Occidental will expire at the May 4, 2012, 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 23, 2012	Positions with Occidental and Subsidiaries and Employment History
Stephen I. Chazen	65	Chief Executive Officer since 2011 and President since 2007; 2010-2011, Chief Operating Officer; 1999-2010, Chief Financial Officer; 2005-2007, Senior Executive Vice President; Director since 2010.
Dr. Ray R. Irani	77	Executive Chairman since 2011; 1990-2011, Chairman and Chief Executive Officer; 2005-2007, President; Director since 1984.
Donald P. de Brier	71	Executive Vice President, General Counsel and Secretary since 1993.
James M. Lienert	59	Executive Vice President and Chief Financial Officer since 2010; 2006-2010, Executive Vice President — Finance and Planning.
William E. Albrecht	60	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; Noble Royalties, Inc.: 2006-2007, President of Acquisitions and Divestitures.
Edward A. "Sandy" Lowe	60	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; Dolphin Energy Ltd.: 2002-2007, Executive Vice President and General Manager.
Roy Pineci	49	Vice President, Controller and Principal Accounting Officer since 2008; 2007-2008, Senior Vice President, Finance — Oil and Gas; 2005-2007, Vice President — Internal Audit.
B. Chuck Anderson	52	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 33,819 stockholders of record at December 31, 2011, and by approximately 475,000 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 $0.46 for all quarters of 2011 ($1.84 for the year). On February 9, 2012, a quarterly dividend of $0.54 per share was declared on the common stock, payable on April 15, 2012 to stockholders of record on March 9, 2012. 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.

Securities Authorized for Issuance under Equity Compensation Plans

All of Occidental's equity 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 was approximately 66 million as of December 31, 2011. The following is a summary of the securities reserved 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))
782,213 (1)			$26.34			52,029,976 (2)

(1)

20,403 shares reserved for issuance pursuant to deferred stock unit awards and 1,845 shares reserved for issuance as dividend equivalents on deferred stock unit awards; and

(2)

Of these shares, depending on the type of award granted, approximately 8.8 million to 26.3 million shares were available at December 31, 2011 for grants of future awards. The number available is less than 52 million shares because a plan provision requires each share covered by an award (other than options and stock appreciation rights) to be counted as three shares against the number of shares available for future awards. Applying this provision to the remaining 52 million shares, approximately 26 million shares have been reserved for currently outstanding but unvested awards and for previously vested and issued shares. The available share number varies because options and stock appreciation rights reduce the shares remaining for future awards only by the number of shares issuable under the award (rather than three times that number). Failure of currently outstanding awards to vest would increase the shares available for future awards by three times the number of shares covered by such awards. For example, if all awards that are currently outstanding failed to vest, approximately 39 million shares would be available for grants of future awards.

Share Repurchase Activities

Occidental’s share repurchase activities for the year ended December 31, 2011, 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 2011	129,521	$	103.07	—
Second Quarter 2011	264,560	$	112.90	—
Third Quarter 2011	2,100,000	$	77.57	2,100,000
October 1 - 31, 2011	564,772	$	77.66	420,000
November 1 - 30, 2011	180,182	$	95.69	70,000
December 1 - 31, 2011	80,000	$	88.22	80,000
Fourth Quarter 2011	824,954	$	82.62	570,000
Total 2011	3,319,035	$	82.64	2,670,000	24,485,575	(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.

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 groups over the five-year period ended on December 31, 2011. 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) in the stock of the companies in the S&P 500 and (iii) in each of the current and prior peer group companies' common stock weighted by their relative market values within the respective peer groups and that all dividends were reinvested.

In 2011, Occidental revised its current peer group due to a significant decrease in market capitalization and restructuring of a previously included entity. Prior to the revision, Occidental's peer group consisted of Anadarko Petroleum Corporation, Apache Corporation, Canadian Natural Resources Limited, Chevron Corporation, ConocoPhillips, Devon Energy Corporation, EOG Resources Inc., ExxonMobil Corporation, Hess Corporation, Marathon Oil Corporation, Royal Dutch Shell plc and Occidental. Occidental's current 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.

12/31/06		12/31/07	12/31/08	12/31/09	12/31/10	12/31/11
	$100	$160	$127	$176	$216	$210
	100	129	97	104	122	136
	100	128	96	104	119	130
	100	105	66	84	97	99

	The information provided in this Performance Graph shall not be deemed "soliciting material" or "filed" with the Securities and Exchange Commission or subject to Regulation 14A or 14C under the Securities Exchange Act of 1934 (Exchange Act), other than as provided in Item 201 to Regulation S-K under the Exchange Act, or subject to the liabilities of Section 18 of the Exchange Act and shall not be deemed incorporated by reference into any filing under the Securities Act of 1933 or the Exchange Act except to the extent Occidental specifically requests that it be treated as soliciting material or specifically incorporates it by reference.

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

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,	2011			2010			2009			2008			2007
results of operations (a)
Net sales	$	23,939		$	19,045		$	14,814		$	23,713		$	18,323
Income from continuing operations (b)	$	6,640		$	4,569		$	3,151		$	7,183		$	5,072
Net income attributable to common stock	$	6,771		$	4,530		$	2,915		$	6,857		$	5,400
Basic earnings per common share from continuing operations (b)	$	8.16		$	5.62		$	3.88		$	8.77		$	6.06
Basic earnings per common share (b)	$	8.32		$	5.57		$	3.59		$	8.37		$	6.45
Diluted earnings per common share (b)	$	8.32		$	5.56		$	3.58		$	8.34		$	6.42

financial position (a)
Total assets	$	60,044		$	52,432		$	44,229		$	41,537		$	36,519
Long-term debt, net	$	5,871		$	5,111		$	2,557		$	2,049		$	1,741
Stockholders’ equity	$	37,620		$	32,484		$	29,159		$	27,325		$	22,858

market capitalization (c)	$	75,992		$	79,735		$	66,050		$	48,607		$	63,573

cash flow
Operating:
Cash provided by operating activities	$	12,281		$	9,566		$	5,946		$	10,765		$	6,831
Investing:
Capital expenditures	$	(7,518	)	$	(3,940	)	$	(3,245	)	$	(4,126	)	$	(3,038	)
Cash used by all other investing activities, net	$	(2,385	) (d)	$	(5,355	)	$	(2,221	)	$	(5,314	)	$	(70	)
Financing:
Cash dividends paid	$	(1,436	)	$	(1,159	)	$	(1,063	)	$	(940	)	$	(765	)
Cash provided (used) by all other financing activities, net	$	261		$	2,242		$	30		$	(570	)	$	(2,333	)

dividends per common share	$	1.84		$	1.47		$	1.31		$	1.21		$	0.94

weighted average basic shares outstanding (thousands)		812,075			812,472			811,305			817,635			834,932

Note: Argentine operations were sold in February 2011 and have been reflected as discontinued operations for all 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, $116 million in 2008 and $75 million in 2007. There were no noncontrolling interests in 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.

Item 7 and 7A

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

Strategy

General

In this report, "Occidental" refers to 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, NGLs and natural gas. The chemical segment mainly manufactures and markets basic chemicals and vinyls. The midstream, marketing and other segment gathers, treats, processes, transports, stores, purchases and markets oil, condensate, NGLs, natural gas, CO2 and power. It also trades around its assets, including pipelines and storage capacity, and trades oil, NGLs, gas and other commodities.

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 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.

Occidental prefers to seek growth of oil and gas production by holding 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. Capital is employed to operate segment assets in a safe and environmentally sound manner. Management expects such assets to contribute substantially to earnings and cash flow after invested capital. Management currently believes its growth will be most strongly affected by the success of the development plans for its California prospects, the Permian development program, Oman and the Shah Gas Field development project in Abu Dhabi.

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. Capital is employed to operate the chemical business in a safe and environmentally sound manner, to sustain production capacity and to focus on projects designed to improve the competitiveness of these assets. Acquisitions may be pursued when they are expected to enhance the existing core chlor-alkali and PVC businesses or take advantage of other specific opportunities.

The midstream and marketing segment is also managed to generate returns on capital employed in excess of Occidental's cost of capital. In marketing its own production and third-party purchases, Occidental attempts to maximize realized prices and margins and limit credit risk exposure. In commodities trading, Occidental seeks to generate gains using net-long positions. Capital is employed to operate segment assets in a safe and environmentally sound manner, to sustain or, where appropriate, increase operational capacity and to improve the competitiveness of Occidental's assets.

Occidental maintains financial discipline by prioritizing the uses of its cash flows in the following order:

Ø	Maintenance capital
Ø	Dividends
Ø	Growth capital
Ø	Acquisitions
Ø	Share repurchases

Oil and Gas

Segment Earnings

($ millions)

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 proved reserves 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 the first quarter of 2011, Occidental sold its Argentine oil and gas operations for after-tax proceeds of approximately $2.6 billion. In 2011, Occidental also completed the acquisition of producing properties in South Texas for approximately $1.8 billion and acquired other domestic oil and gas assets, which included properties in California, as well as the Permian and Williston Basins for approximately $2.6 billion.

Internationally, Occidental acquired a 40-percent participating interest in the Shah Gas Field development project in Abu Dhabi, which is operated by Abu Dhabi Gas Development Company Limited (Al Hosn Gas Project), in the first quarter of 2011. Occidental partnered with the Abu Dhabi National Oil Company in a 30-year joint venture agreement for the $10 billion project, of which Occidental’s portion is approximately $4 billion. In May 2011, Occidental paid approximately $500 million for its share of pre-acquisition development expenditures. Approximately $460 million of this amount related to expenditures recorded in the midstream and marketing segment.

In addition, Occidental continues to deploy significant capital to its core operations in the Permian Basin and California, as well as in Iraq, Oman and Qatar, to increase production from these assets.

Chemical

Segment Earnings

($ millions)

OxyChem’s strategy is to be a low-cost producer in order to maximize its cash flow generation. OxyChem concentrates on the chlorovinyls chain beginning with chlorine, which is co-produced with caustic soda, both of which are marketed 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 economies of scale.

Midstream, Marketing and Other

Segment Earnings

($ millions)

The midstream and marketing segment is managed to generate returns on capital invested in excess of Occidental's cost of capital. In order to generate these returns, the segment provides low-cost services to other segments and operates and invests in gas plants and oil, gas, NGLs and CO2 pipeline systems and storage facilities. It also provides similar services to third parties. In addition, the marketing and trading group markets Occidental's and third-party oil and gas, trades around the midstream and marketing segment assets and engages in commodities trading.

Key Performance Indicators

General

Occidental seeks to meet its strategic goals by continuously measuring its success in its key performance metrics, which ultimately drives total stockholder return. Occidental believes the following are the most significant metrics that maximize total stockholder return:

Ø	Dividend growth;
Ø	Production growth in the oil and gas segment;
Ø	Return on equity (ROE) and return on capital employed (ROCE).

In addition, Occidental monitors other segment-specific measures such as per-unit profit, production cost, cash flow, finding and development cost and others.

Occidental's oil and gas production has grown a cumulative 15 percent for the three-year period from 2008 through 2011. Based on the $2.16 per share annual dividend rate announced in February 2012, Occidental’s dividend rate has increased by 332 percent in 10 years. While Occidental's stockholders' equity increased by 16 percent for 2011 and 29 percent for the three-year period from 2009 through 2011, it continued to deliver above-cost-of-capital returns as follows:

	Annual 2011 (a)	Three-Year Annual Average 2009 - 2011 (b)
ROE	19.3%	15.0%
ROCE	17.2%	13.5%

(a)	The ROE and ROCE for 2011 were calculated by dividing Occidental's 2011 net income attributable to common stock (taking into account after-tax cost of capital for ROCE) by its average equity and capital employed, respectively, during 2011.
(b)	The three-year average ROE and ROCE were calculated by dividing Occidental's average net income attributable to common stock (taking into account after-tax cost of capital for ROCE) over the three-year period 2009-2011 by its average equity and capital employed, respectively, over the same period.

As a result, through December 31, 2011, Occidental’s total stockholder return has been 110 percent over the past five years and 769 percent over the past 10 years.

Debt Structure

Occidental’s year-end 2011 total debt-to-capitalization (debt and equity) ratio was 13 percent. In the first quarter of 2011, Occidental redeemed $1.4 billion of senior notes. Occidental issued $2.15 billion of senior unsecured notes in the third quarter of 2011.

Occidental has a $2.0 billion bank credit facility (2011 Credit Facility). The interest rate on any borrowings under the 2011 Credit Facility is based in part on Occidental’s senior debt ratings. Occidental’s long-term senior unsecured debt was rated A by Fitch Ratings, Standard and Poor’s Ratings and DBRS. Occidental’s long-term unsecured debt was rated A2 by Moody’s Investors Service. A security rating is not a recommendation to buy, sell or hold securities, may be subject to revision or withdrawal at any time by the assigning rating organization and should be evaluated independently of any other rating.

Oil and Gas Segment

Business Environment

Oil and gas prices are the major variables that drive the industry’s short- and intermediate-term financial performance. Average oil prices were higher in 2011 than 2010. The average daily per barrel WTI and Brent market prices, respectively, for 2011 were $95.12 and $110.90, compared with $79.53 and $79.61 in 2010. Approximately 60 percent of Occidental’s oil production tracks world oil prices, such as Brent, and 40 percent is indexed to WTI. Occidental’s average realized price for oil as a percentage of average WTI and Brent prices was approximately 103 percent and 88 percent for 2011, and 95 percent and 94 percent for 2010, respectively. Occidental's average realized price for NGLs as a percentage of average WTI price was approximately 56 percent and 57 percent for 2011 and 2010, respectively.

The average daily New York Mercantile Exchange (NYMEX) domestic natural gas price in 2011 decreased approximately 8 percent from 2010. For 2011, the price averaged $4.11 per Mcf compared with $4.49 per Mcf for 2010, and was $2.99 per Mcf as of December 31, 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 are extended through the end of production once production commences. Of the total 7.4 million net acres domestically where Occidental conducts its operations, 73 percent is leased, 26 percent represents owned subsurface mineral rights and for 1 percent it owns both land and the mineral rights.

Production-Sharing Contracts (PSC)

Occidental has interests in Bahrain, Iraq, Libya, Oman, Yemen and Qatar, including Dolphin, that are operated under PSCs or similar contracts. Under such contracts, Occidental receives a share of production and reserves to recover its costs and an additional share for profit. In addition, Occidental's share of production and reserves from 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 Sales Volumes

(thousands BOE/day)

Notes:
*	Includes average sales volumes per day of 4 thousand barrels (mbbl), 6 mbbl, 6 mbbl and 5 mbbl for 2010, 2009, 2008 and 2007, respectively, related to the noncontrolling interest in a Colombian subsidiary.
*	Excludes average sales volumes per day of 5 thousand barrels of oil equivalent (MBOE), 43 MBOE, 42 MBOE, 36 MBOE and 36 MBOE for 2011, 2010, 2009, 2008 and 2007, respectively, related to the Argentine operations sold in February 2011 and classified as discontinued operations.

United States Assets


		United States 1. Permian 2. Elk Hills and other California interests 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, with the entire basin accounting for approximately 16 percent of the total United States oil production. Occidental is the largest producer of oil in the Permian Basin with an approximate 15-percent net share of the total production. Occidental also produces and processes natural gas and NGLs in the Permian Basin.

In the past several years, including 2011, Occidental increased its Permian interests through various acquisitions.

Occidental’s interests in Permian offer additional development and exploitation potential. During 2011, Occidental drilled approximately 409 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.

Approximately 64 percent of Occidental’s Permian oil production is from fields that actively employ the application of 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. During 2011, Occidental’s non-CO2 operations increased their development program, which accounted for more than half of the wells drilled in Permian.

Occidental's total share of production in Permian was approximately 198,000 BOE per day in 2011.

California

Occidental's California operations consist of holdings in the Elk Hills area, the Wilmington and other fields in the Los Angeles basin and interests in the Ventura, San Joaquin and Sacramento basins. Occidental's properties in California consist of more than 90 fields.

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 2011, 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 330 new wells being drilled.

Occidental began construction of a new gas processing plant in the Elk Hills area in 2010, which is expected to be completed in 2012.

Occidental holds approximately 1.7 million acres in California, the vast 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. In all of California during 2011, Occidental drilled approximately 675 wells and performed approximately 500 workovers.

Occidental's share of production and reserves from its operations in the Wilmington Field is subject to contractual arrangements similar to a PSC.

Occidental's total share of production in California was approximately 138,000 BOE per day in 2011.

Midcontinent and Other

The Midcontinent properties, which include interests in the Hugoton Field and the Piceance Basin, are located in Colorado, Utah, Kansas and Oklahoma. Occidental holds over 2.4 million net acres in the midcontinent region, which includes 1.4 million acres in a large concentration of gas reserves and production and royalty interests in the Hugoton area located in Kansas and Oklahoma, and approximately 1.0 million acres in Colorado and Utah.

Other interests are located in North Dakota, Montana, South Texas and West Virginia. In January 2011, Occidental completed the acquisition of producing properties in South Texas. Occidental holds approximately 138,000 net acres in South Texas. Occidental also holds approximately 277,000 net acres of oil producing and prospective unconventional properties in North Dakota’s Williston Basin, including acreage in the Bakken and Three Forks formations. A substantial portion of this acreage was purchased in 2011 and 2010. In addition, Occidental holds 229,000 net acres in West Virginia.

In Midcontinent and Other, Occidental drilled approximately 270 wells and produced approximately 92,000 BOE per day in 2011. Occidental expects to reduce drilling activity for gas wells in 2012.

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

Bahrain

In 2009, Occidental and its partners 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, Occidental and its partners have increased gross gas production capacity more than 40 percent from an initial level of 1.5 billion cubic feet per day to over 2.1 billion cubic feet per day and increased gross oil production by 60 percent from 26,000 barrels per day to 42,000 barrels per day. Occidental plans to continue growing gross gas production capacity to over 2.3 billion cubic feet per day and gross oil production to over 75,000 barrels. Occidental's share of production from Bahrain during 2011 was approximately 173 million cubic feet (MMcf) of gas and 4,000 barrels of oil per day.

Iraq

In 2010, Occidental and its partners 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 of approximately 180,000 BOE per day in 2010. Occidental and its partners plan 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 in Iraq was approximately 7,000 BOE per day in 2011.

Libya

Occidental, under agreements with the Libyan National Oil Corporation, participates in Sirte Basin producing operations. These agreements continue through 2032.

In early 2011, Occidental ceased exploration activities and its participation in production operations in Libya due to civil unrest in the country and United States sanctions. The United States government lifted its sanctions in September 2011 and Occidental resumed its participation in the producing operations at that time. Occidental Libya’s 2011 and 2010 production volumes were approximately 4,000 and 13,000 BOE per day, representing less than 1 percent and 2 percent, respectively, of Occidental’s worldwide volumes.

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.

Occidental and its partners signed a 30-year PSC for the Mukhaizna Field (Block 53) with the Government of Oman in 2005, pursuant to which Occidental assumed operations of the field. By the end of 2011, Occidental had drilled over 1,400 new wells and continued implementation of a major steam flood project. As of year-end 2011, the exit rate of gross daily production was over 16 times higher than the production rate in September 2005, reaching 124,000 BOE per day. Occidental plans to steadily increase production through continued expansion of the steam flood project.

The term for Block 9 is through December 2015, with a potential 10-year extension. The term for Block 27 is through September 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 the Oman properties was approximately 76,000 BOE per day in 2011.

Qatar

Occidental operates three offshore projects in Qatar: Idd El Shargi North Dome (ISND) and Idd El Shargi South Dome (ISSD), with a 100-percent working interest in each project, and Al Rayyan (Block 12), with a 92.5-percent working interest. The terms for ISND, ISSD and Block 12 extend through 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. Drilling under this phase is planned to be completed in 2012. Occidental also received approval for field development plans for ISSD and Al Rayyan, which would include additional drilling through 2013.

Occidental also has an investment in Dolphin, which was acquired in 2002, consisting of two separate economic interests through which Occidental owns: (i) a 24.5-percent undivided interest in the 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 all of its operations in Qatar was approximately 126,000 BOE per day in 2011.

United Arab Emirates

In the first quarter of 2011, Occidental acquired a 40-percent participating interest in the Al Hosn Gas Project. Occidental partnered with the Abu Dhabi National Oil Company in a 30-year joint venture agreement for the project. 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 2011 capital expenditures for this project were approximately $460 million, with an additional $500 million paid for Occidental's share of pre-acquisition development expenditures. A substantial portion of the total expenditures to date have been incurred in connection with plants and facilities, which are included in the midstream and marketing segment. As the development project progresses, higher portions of the capital will be spent to drill wells, which will be reflected in the oil and gas segment. Occidental believes that its share of remaining capital until production from the field begins (expected to be in 2014), will be approximately $3 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

Occidental owns contractual interests in two producing blocks in Yemen, Block 10 East Shabwa Field 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. Occidental’s working interests in the Block 14 Masila Field expired in December 2011.

Occidental's share of production from the Yemen properties was approximately 27,000 BOE per day in 2011, which included nearly 11,000 BOE per day from the Masila Field.

Latin America Assets

Latin America

1. Bolivia

2. Colombia

Bolivia

Occidental holds working interests in four blocks located in the Tarija, Chuquisaca and Santa Cruz regions of Bolivia.

Colombia

Occidental is the operator under four contracts within the Llanos Norte Basin: the Cravo Norte, Rondón, Cosecha and Chipirón association contracts. Occidental’s working interests under these four contracts are 39 percent, 44 percent, 53 percent and 61 percent, respectively. Occidental also holds a 48-percent working interest in the La Cira-Infantas Field, which is located in the Middle-Magdalena Basin. Occidental's share of 2011 production from its Colombian operations was approximately 29,000 BOE per day.

Proved Reserves

For further information regarding Occidental's proved reserves, see "Supplemental Oil and Gas Information" following the "Financial Statements."

Occidental had proved reserves at year-end 2011 of 3,176 million BOE, as compared with the year-end 2010 amount of 3,167 million BOE. Proved reserves at year-end 2011 and 2010 consisted of, respectively, 63 percent and 64 percent oil, 9 percent and 9 percent NGLs and 28 percent and 27 percent natural gas. Proved developed reserves represented approximately 76 percent of Occidental’s total proved reserves at year-end 2011 and 2010.

Proved Reserve Additions

Occidental's total proved reserve additions from all sources were 276 million BOE in 2011. The total additions were as follows:

In millions of BOE
Improved recovery	264
Extensions and discoveries	25
Purchases	201
Revisions of previous estimates	(214	)
Total additions	276

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, 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 or not these historical sources of proved reserve additions continue at similar levels.

Revisions of Previous Estimates

Revisions can include upward or downward changes to previous proved reserves estimates for existing fields due to the evaluation of existing or new geologic, production decline or operating performance data, or changes in prices and costs that are used in reserves estimations. In 2011, revisions of previous estimates provided a net 214 million BOE reduction to reserves.

Oil price changes affect proved reserves recorded by Occidental. For example, when oil prices increase, less oil volume is required to recover costs under PSCs, which results in a reduction of Occidental’s share of proved reserves. Conversely, when oil prices drop, Occidental’s share of proved reserves increases for these PSCs. Oil and natural gas price changes also affect the economic lives of proved reserves, primarily in domestic properties, in a manner offsetting these PSC effects, because higher prices result in longer reservoir lives and more reserves.

In 2011, Occidental’s domestic reserves had a positive price-related revision as a result of higher oil prices, net of negative revisions in certain properties resulting from lower gas prices during the year. International reserves had negative price adjustments due to high oil prices. Price adjustments for the company as a whole were negative. If the currently prevailing natural gas prices stay at depressed levels for an extended period, domestic gas reserves could experience a further negative price revision at the end of 2012.

Other revisions outside the United States were largely in Libya and Iraq. In Libya, the revision was the result of the current situation in the country where development plans for proved undeveloped reserves have not yet been put into effect. In Iraq, a slower than

expected pace of the development resulted in a revision to the proved undeveloped reserves. In both countries, Occidental expects that these reserves will be reinstated as the development plans progress. Other revisions internationally were caused by the performance of previously drilled wells.

In the United States, other revisions were caused by performance issues related to wells drilled in prior periods. 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.

Apart from the effects of product prices, Occidental believes its approach to interpreting technical data regarding proved oil and gas reserves makes it more likely that future proved reserve revisions will be positive rather than negative.

Improved Recovery

In 2011, Occidental added proved reserves of 264 million BOE from improved recovery through its EOR and infill drilling activities. Generally, the improved recovery additions in 2011 were associated with the continued development of properties in California, Permian, Williston, Oman, Colombia and Bahrain. These properties are generally characterized by the deployment of secondary and tertiary development projects, largely employing application of waterflood (secondary), steamflood (tertiary) or CO2 (secondary or tertiary) injection. These development projects 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. 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 2011, extensions and discoveries added 25 million BOE.

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 2011, Occidental added 201 million BOE through purchases of proved reserves largely consisting of several domestic acquisitions in South Texas, the Permian Basin and California.

Proved Undeveloped Reserves

In 2011, Occidental had proved undeveloped reserves additions of 307 million BOE from improved recovery, extensions and discoveries and purchases. Of the total additions, 186 million BOE represented additions from improved recovery, primarily in California, Permian, Williston, Oman, Colombia, Bahrain and Qatar. Occidental added 106 million BOE through purchases of proved undeveloped reserves domestically in South Texas, the Permian Basin and California. These proved undeveloped reserve additions were offset by reserves transfers of 178 million BOE to the proved developed category as a result of the 2011 development programs. Occidental incurred approximately $2.7 billion in 2011 to convert proved undeveloped reserves to proved developed reserves. Permian, California, Midcontinent, Oman, Qatar and Bahrain accounted for approximately 89 percent of the reserves transfers from proved undeveloped to proved developed in 2011. Costs to develop proved undeveloped reserves have increased over time and costs of transfers to proved developed reserves 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, 2011, 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 toward the development of 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.

The current Senior Director of Worldwide Reserves and Reservoir Engineering 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 Director 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 Director 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 monitor, 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 2011, 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, 2011, 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 2011 year-end total proved reserves portfolio. In 2011, 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 76 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 generally increased throughout 2011, settling at $98.83 per barrel and $107.38 per barrel as of December 31, 2011.

Oil prices will continue to be affected by (i) global supply and demand, which is generally a function of global economic conditions, inventory levels, production disruptions, currency exchange rates, and the actions of OPEC, other significant producers and governments, and (ii) 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 forecast gas prices reliably.

Chemical Segment

Business Environment

Chemical segment earnings increased in 2011 as certain economies continued to recover from the global economic downturn. Higher margins across most product lines were achieved as prices more than offset higher feedstock costs.

Business Review

Basic Chemicals

During 2011, United States and international manufacturing sectors continued to recover from the global economic downturn resulting in strong demand and pricing for basic chemical products. Industry chlorine production increased by 2 percent, compared to 2010, as chlorine demand in emerging economies continued to outpace United States demand. Exports of downstream chlorine derivatives 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 improved each quarter of 2011 partly as a result of major global events, including the devastating tsunami in Japan, which led to an increase in exports of 7 percent over 2010. Chlorine prices remained steady throughout the year, and began to decrease during the fourth quarter due to seasonal slowdowns, which negatively impacted overall chlorine demand.

Vinyls

Year-over-year domestic vinyls demand fell 3.6 percent due to the persistent low demand from the housing and commercial construction markets. Consequently, domestic operating rates in 2011 were down 1 percent compared to 2010, and margins also decreased in 2011. In addition, ethylene costs, which contribute significantly to feedstock costs, increased

globally in 2011. However, North American-produced ethylene continues to cost significantly less compared to costs in Europe and Asia, giving North American vinyl products an advantage in global markets. As a result, Occidental's vinyl exports in 2011 were 19 percent higher compared to 2010.

Industry Outlook

Future performance will depend on the recovery of domestic housing and construction markets, positive global economic activity, and the cost competitiveness of United States feedstock and energy pricing compared to global markets.

Basic Chemicals

Occidental expects that if the United States housing, automotive and durable goods sectors continue to improve, it should experience higher domestic demand for basic chemical products in 2012. With the stronger demand, chlorine and caustic soda margins would be expected to generally remain at 2011 levels. The continued competitiveness of downstream chlorine derivatives in global markets is contingent on United States feedstock costs remaining favorable compared to other global markets.

Vinyls

If the United States economy continues to improve, domestic demand for vinyls and operating rates would also be expected to improve in 2012, which should result in better domestic margins. Occidental expects export demand to remain firm, but for margins to be challenged as North American ethylene producers operate near capacity reducing the United States cost advantages compared to other vinyl producing regions of the world.

Midstream, Marketing and Other Segment

Business Environment

Midstream and marketing segment earnings are affected by the performance of its marketing and trading businesses and its processing and transportation assets. The marketing and trading businesses earn margins from trading oil, gas and other commodities, marketing the oil and gas segment's products and storage activity. 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 were modestly lower in 2011, compared to 2010, reflecting lower marketing and trading income, partially offset by higher pipeline income.

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 the midstream and marketing segment assets and engages in commodities trading. Occidental’s third-party marketing and trading activities focus on purchasing oil, NGLs and gas for resale from partners, producers and third parties whose oil and gas supply is located near its midstream and marketing assets, such as pipelines, processing plants and storage facilities. These purchases allow Occidental to aggregate volumes to maximize prices received for Occidental’s production. In addition, Occidental’s Phibro trading unit's strategy is to profit from market price changes. Marketing and trading earnings are affected primarily by commodity price changes and margins in oil and gas transportation and storage programs. In 2011, the marketing and trading group earnings decreased due to lower trading results.

Gas Processing Plants and CO2 Fields and Facilities

Occidental processes its and third-party domestic wet gas to extract NGLs and other gas by-products, 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 2011 earnings from these operations improved compared to 2010, due to higher gas processing volumes and higher NGL prices.

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. Through its 24.5-percent interest in Dolphin Energy, the Dolphin Pipeline investment contributes significantly to Occidental's pipeline transportation results. The Dolphin Pipeline has a 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 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-gathering, 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 as well as 64 truck unloading facilities at various points along the system, which allow for additional volumes to be delivered into the pipeline.

Occidental owns approximately 35 percent of the General Partner of Plains All-American Pipeline, L.P. (Plains Pipeline), an oil and gas pipeline transportation, storage, terminalling and marketing entity.

Occidental’s 2011 pipeline transportation earnings improved due to better revenues and margins from all of these assets.

Power Generation Facilities

Earnings from power generation facilities are derived from the sales of steam and power to affiliates and third parties. Occidental’s 2011 earnings from these facilities were flat compared to 2010. On December 31, 2010, Occidental 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, bringing Occidental's total ownership to 100 percent.

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. The trading and marketing business is inherently volatile. Based on its framework of controls and risk management systems, Occidental does not expect the volatility of these operations to be significant to the company as a whole.

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,	2011			2010			2009
net sales (a)
Oil and Gas	$	18,419		$	14,276		$	11,009
Chemical		4,815			4,016			3,225
Midstream, Marketing and Other		1,447			1,471			1,016
Eliminations (a)		(742	)		(718	)		(436	)
	$	23,939		$	19,045		$	14,814
earnings
Oil and Gas (b,c)	$	10,241		$	7,151		$	5,097
Chemical		861			438			389
Midstream, Marketing and Other		448			472			235
		11,550			8,061			5,721
Unallocated corporate items
Interest expense, net (d)		(284	)		(93	)		(102	)
Income taxes (e)		(4,201	)		(2,995	)		(2,063	)
Other (f)		(425	)		(404	)		(405	)
Income from continuing operations (b)		6,640			4,569			3,151
Discontinued operations, net (g)		131			(39	)		(236	)
Net Income (b)	$	6,771		$	4,530		$	2,915

Basic Earnings per Common Share	$	8.32		$	5.57		$	3.59

(a)	Intersegment sales eliminate upon consolidation and are generally made at prices approximately equal to 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 noncontrolling interest amounts of $72 million and $51 million for 2010 and 2009, respectively.
(c)	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 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. The 2009 amount includes an $8 million pre-tax charge for the termination of rig contracts.
(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. The 2009 amount includes tax benefits of $87 million resulting from relinquishment of exploration properties.
(f)	The 2009 amount includes a $40 million pre-tax charge related to severance and a $15 million pre-tax charge for railcar leases.
(g)	The 2011 amount includes a $144 million after-tax gain from the sale of the Argentine operations. The 2009 amount includes an after-tax charge of $111 million for asset impairments of certain Argentine producing properties.

Oil and Gas

Dollars in millions, except as indicated	2011		2010		2009
Segment Sales	$	18,419	$	14,276	$	11,009
Segment Earnings	$	10,241	$	7,151	$	5,097

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, 2011. 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	2011		2010		2009
United States
Oil (MBBL)
California		80		76		76
Permian		134		136		141
Midcontinent and Other		16		7		6
Total		230		219		223
NGLs (MBBL)
California		15		16		17
Permian		38		29		27
Midcontinent and Other		16		7		4
Total		69		52		48
Natural gas (MMCF)
California		260		280		250
Permian		157		199		199
Midcontinent and Other		365		198		186
Total		782		677		635
Latin America (a)
Oil (MBBL) – Colombia (b)		29		37		45
Natural gas (MMCF) – Bolivia		15		16		16
Middle East/North Africa
Oil (MBBL)
Bahrain		4		3		―
Dolphin		9		11		15
Iraq		7		3		―
Libya		4		12		10
Oman		67		62		50
Qatar		73		76		79
Yemen		27		31		34
Total		191		198		188
NGLs (MBBL)
Dolphin		10		13		11
Libya		―		1		1
Total		10		14		12
Natural gas (MMCF)
Bahrain		173		169		10
Dolphin		199		236		257
Oman		54		48		49
Total		426		453		316
Total Production (MBOE) (a,c)		733		711		677
(See footnotes following the Average Sales Price table)

Sales Volumes per Day	2011		2010		2009
United States
Oil (MBBL)		230		219		223
NGLs (MBBL)		69		52		48
Natural gas (MMCF)		782		677		635
Latin America (a)
Oil (MBBL) – Colombia (b)		29		36		45
Natural gas (MMCF) – Bolivia		15		16		16
Middle East/North Africa
Oil (MBBL)
Bahrain		4		3		―
Dolphin		9		12		14
Iraq		3		―		―
Libya		4		12		12
Oman		69		61		50
Qatar		73		76		79
Yemen		27		30		35
Total		189		194		190
NGLs (MBBL)
Dolphin		10		12		11
Libya		―		1		―
Total		10		13		11
Natural gas (MMCF)		426		453		316
Total Sales Volumes (MBOE) (a,c)		731		705		678
(See footnotes following the Average Sales Price table)

	2011		2010		2009
Average Sales Prices
Oil Prices ($ per bbl)
United States	$	92.80	$	73.79	$	56.74
Latin America (a)	$	97.16	$	75.29	$	55.89
Middle East/North Africa	$	104.34	$	76.67	$	58.75
Total worldwide (a)	$	97.92	$	75.16	$	57.31
NGL Prices ($ per bbl)
United States	$	59.10	$	48.86	$	37.26
Middle East/North Africa	$	32.09	$	30.64	$	21.88
Total worldwide	$	55.53	$	45.08	$	34.27
Gas Prices ($ per Mcf)
United States	$	4.06	$	4.53	$	3.46
Latin America (a)	$	10.11	$	7.73	$	5.70
Total worldwide (a)	$	3.01	$	3.11	$	2.83
Expensed Exploration (d)	$	258	$	262	$	254
Capital Expenditures
Development	$	5,686	$	2,955	$	2,274
Exploration	$	421	$	194	$	132
Other	$	38	$	17	$	42

(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 volumes per day of 5 mbbl and 6 mbbl for the years ended December 31, 2010 and 2009, respectively, related to the noncontrolling interest in a Colombian subsidiary. Includes sales volumes per day of 4 mbbl and 6 mbbl for the years ended December 31, 2010 and 2009, respectively, 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.
(d)	Includes dry hole write-offs and lease impairments of $160 million in 2011, $139 million in 2010 and $200 million in 2009. The 2011 amount includes a $35 million Libya exploration write-off.

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 depreciation, depletion and amortization (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.

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, including the effect of post-acquisition capital investment, 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. 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 2010 were $7.2 billion compared to $5.1 billion in 2009. The increase reflected higher average worldwide oil, NGL and domestic natural gas prices and higher volumes, partially offset by higher operating expenses partly resulting from fully expensing CO2, higher field support and workover expenses and higher DD&A rates.

Daily oil and gas production volumes were 711,000 BOE for 2010, compared with 677,000 BOE for 2009. The increase was mainly due to the new production in Bahrain, higher production in the Mukhaizna Field in Oman, and gas production from domestic assets, which were partially offset by a decline in Colombia. Production was negatively impacted in the Middle East/North Africa, Long Beach and Colombia by higher year-over-year average oil prices affecting PSCs by 16,000 BOE per day. Daily sales volumes were 705,000 BOE in the twelve months of 2010, compared with 678,000 BOE for 2009.

Oil and gas segment earnings in 2011 include 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.

Oil and gas segment earnings in 2010 included a pre-tax charge of $275 million for asset impairments, predominately of gas properties in the Rocky Mountain region. Oil and gas segment earnings in 2009 included an $8 million pre-tax charge for the termination of rig contracts.

Average production costs for 2011, excluding taxes other than on income, were $12.84 per BOE, compared to $10.19 for 2010. The increase resulted from higher workover and well maintenance activity driven by Occidental’s program to increase production at current increased oil prices. We expect further increases in the activity level in 2012.

Chemical

In millions	2011		2010		2009
Segment Sales	$	4,815	$	4,016	$	3,225
Segment Earnings	$	861	$	438	$	389
Capital Expenditures	$	234	$	237	$	205

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.

Chemical segment earnings were $438 million in 2010, compared to $389 million in 2009. The increase in 2010 reflected improved market conditions, particularly for exports, driven by favorable feedstock costs in North America compared to Europe and Asia. Vinyls exports in 2010 were 125 percent higher compared to 2009.

Midstream, Marketing and Other

In millions	2011		2010		2009
Segment Sales	$	1,447	$	1,471	$	1,016
Segment Earnings	$	448	$	472	$	235
Capital Expenditures	$	1,089	$	501	$	554

Midstream and marketing segment earnings in 2011 were $448 million, compared to $472 million in 2010. The 2011 results reflected lower marketing and trading income, partially offset by higher pipeline income.

Midstream and marketing segment earnings in 2010 were $472 million, compared to $235 million in 2009. The 2010 results reflected higher margins in the marketing and trading and gas processing businesses and increased earnings in the pipeline business.

Significant Items Affecting Earnings

The following table sets forth, for the years ended December 31, 2011, 2010 and 2009, 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)	2011			2010			2009
oil and gas
Libya exploration write-off	$	(35	)	$	―		$	―
Gains on sale of Colombian pipeline interest		22			―			―
Foreign tax		(29	)		―			―
Asset impairments		―			(275	)		―
Rig contract terminations		―			―			(8	)
Total Oil and Gas	$	(42	)	$	(275	)	$	(8	)
chemical
No significant items affecting earnings	$	―		$	―		$	―
Total Chemical	$	―		$	―		$	―

midstream, marketing and other
No significant items affecting earnings	$	―		$	―		$	―
Total Midstream, Marketing and Other	$	―		$	―		$	―
corporate
Premium on debt extinguishments	$	(163	)	$	―		$	―
State income tax charge		(33	)		―			―
Severance charge		―			―			(40	)
Railcar leases		―			―			(15	)
Foreign tax credit carry-forwards		―			80			―
Tax effect of pre-tax adjustments		50			100			22
Discontinued operations, net of tax (a)		131			(39	)		(236	)

Total Corporate	$	(15	)	$	141		$	(269	)

(a)

The 2011 amount includes a $144 million after-tax gain from the sale of the Argentine operations. The 2009 amount includes an after-tax charge of $111 million for asset impairments of certain Argentine producing properties.

Taxes

Deferred tax liabilities, net of deferred tax assets of $1.9 billion, were $4.7 billion at December 31, 2011. The current portion of the deferred tax assets of $200 million is included in prepaid expenses and other. 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	2011			2010			2009
EARNINGS
Oil and Gas	$	10,241		$	7,151		$	5,097
Chemical		861			438			389
Midstream, Marketing and Other		448			472			235
Unallocated Corporate Items		(709	)		(497	)		(507	)
Pre-tax income		10,841			7,564			5,214

Income tax expense
Federal and State		1,795			1,087			686
Foreign		2,406			1,908			1,377
Total		4,201			2,995			2,063

Income from continuing operations	$	6,640		$	4,569		$	3,151

Worldwide effective tax rate		39%			40%			40%

Occidental’s 2011 worldwide tax rate was 39 percent, slightly lower than 2010 and 2009 due to higher proportionate domestic pre-tax income in 2011. 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. The 2009 income tax expense included a tax benefit of $87 million resulting from relinquishments of exploration properties.

Consolidated Results of Operations

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

Selected Revenue and Other Income Items

In millions	2011		2010		2009
Net sales	$	23,939	$	19,045	$	14,814
Interest, dividends and other income	$	165	$	111	$	118

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 increases in the oil and gas segment represented approximately 84 percent of the overall increase while chemical segment price and volume increases represented 16 percent of the increase.

The increase in net sales in 2010, compared to 2009, was primarily due to higher oil, NGLs, gas and chemical product prices and volumes. Price and volume increases in the oil and gas segment represented approximately 71 percent of the overall increase, chemical volume and price increases represented 19 percent and midstream and marketing represented the remaining increase.

Selected Expense Items

In millions	2011		2010		2009
Cost of sales (a)	$	7,385	$	6,112	$	5,105
Selling, general and administrative and other operating expenses	$	1,523	$	1,396	$	1,300
Depreciation, depletion and amortization	$	3,591	$	3,153	$	2,687
Taxes other than on income	$	605	$	484	$	425
Exploration expense	$	258	$	262	$	254
Charges for impairments	$	―	$	275	$	―
Interest and debt expense, net	$	298	$	116	$	133

(a)

Excludes DD&A of $3,584 million in 2011, $3,145 million in 2010 and $2,643 million in 2009.

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.

Cost of sales increased in 2010, compared to 2009, due to higher oil and gas production costs, partly resulting from the effects of fully expensing CO2 costs in 2010, as well as higher field operating, workover and well maintenance costs, and higher volumes; and higher chemical volumes, energy and feedstock 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.

Selling, general and administrative and other operating expenses increased in 2010, compared to 2009, due to higher compensation costs, in particular, equity compensation expense due to higher stock prices in 2010.

DD&A increased in 2011, compared to 2010, due to higher DD&A rates and volumes in the oil and gas segment. The DD&A rate is expected to further increase in 2012.

DD&A increased in 2010, compared to 2009, due to higher DD&A rates and volumes, including a full year of operations in Bahrain.

Taxes other than on income increased in 2011, compared to 2010, due to higher realized domestic oil prices and volumes and higher domestic ad valorem taxes resulting from increased property values.

Taxes other than on income increased in 2010, compared to 2009, due to higher production taxes for Permian and Midcontinent resulting from higher realized domestic oil and natural gas prices and higher ad valorem taxes in Permian resulting from increased property values.

Exploration expense was comparable for 2011, 2010 and 2009.

Charges for impairments in 2010 predominately related to gas properties in the Rocky Mountain region.

Interest and debt expense, net, increased in 2011, compared to 2010, mainly due to the $163 million early debt extinguishment charge recorded in the first quarter of 2011.

Interest and debt expense, net, decreased in 2010, compared to 2009, due to lower average interest rates during 2010.

Selected Other Items

(Income)/expense (in millions)	2011			2010			2009
Provision for income taxes	$	4,201		$	2,995		$	2,063
Income from equity investments	$	(382	)	$	(277	)	$	(227	)
Discontinued operations, net	$	(131	)	$	39		$	236
Net income attributable to noncontrolling interest	$	―		$	72		$	51

Provision for domestic and foreign 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 is due to higher proportionate domestic pre-tax income in 2011, compared to 2010.

Provision for domestic and foreign income taxes increased in 2010, compared to 2009, due to higher income before taxes in 2010. The worldwide effective tax rate in 2010 was comparable to 2009. The 2010 income tax expense included an $80 million benefit related to foreign tax credit carryforwards.

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 primarily reflected the $144 million after-tax gain recorded from the sale of the Argentine operations.

Discontinued operations, net, in 2010 primarily reflected the after-tax losses in the Argentine operations held for sale. The 2009 amount included after-tax impairment charges of $111 million for producing properties in Argentina.

There was no noncontrolling interest in 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 the following components of Occidental’s balance sheet are discussed below:

Selected Balance Sheet Components

In millions	2011		2010
CURRENT ASSETS
Cash and cash equivalents	$	3,781	$	2,578
Trade receivables, net		5,395		5,032
Marketing and trading assets and other		916		900
Assets of discontinued operations		―		2,861
Inventories		1,069		1,041
Prepaid expenses and other		381		647
Total current assets	$	11,542	$	13,059
Investments in unconsolidated entities	$	2,072	$	2,039
Property, plant and equipment, net	$	45,684	$	36,536
Long-term receivables and other assets, net	$	746	$	798

CURRENT LIABILITIES
Accounts payable	$	5,304	$	4,646
Accrued liabilities		2,440		2,397
Domestic and foreign income taxes		110		170
Liabilities of discontinued operations		93		612
Total current liabilities	$	7,947	$	7,825
Long-term debt, net	$	5,871	$	5,111
Deferred credits and other liabilities-income taxes	$	4,846	$	3,445
Deferred credits and other liabilities-other	$	3,662	$	3,452
Long-term liabilities of discontinued operations	$	98	$	115
Stockholders’ equity	$	37,620	$	32,484

Assets

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

The increase in trade receivables, net, was due to higher oil and NGL prices and volumes in the fourth quarter of 2011, compared to the fourth quarter of 2010. The decrease in assets of discontinued operations was due to the sale of Occidental’s Argentine operations, which closed in February 2011. The decrease in prepaid expenses and other reflected the closing of the South Texas acquisition in January 2011, for which a deposit was made in 2010.

The increase in PP&E, net, was due to capital expenditures and the acquisitions of oil and gas properties, partially offset by DD&A.

Liabilities and Stockholders' Equity

The increase in the accounts payable and accrued liabilities balances reflected higher capital expenditures during the fourth quarter of 2011 compared to the fourth quarter of 2010. The decrease in liabilities of discontinued operations was due to the sale of Occidental’s Argentine operations.

The increase in long-term debt, net, was due to the issuance of $2.15 billion of senior unsecured notes in August 2011, partially offset by the redemption of $1.4 billion of senior notes in March 2011.

The increase in deferred credits and other liabilities – income taxes was due to higher capital expenditures in 2011. The increase in deferred credits and other liabilities – other reflected the long-term portion of liabilities related to the higher asset retirement obligations. The increase in stockholders’ equity reflected net income for 2011, partially offset by dividend payments and treasury stock purchases.

Liquidity and Capital Resources

At December 31, 2011, Occidental had approximately $3.8 billion in cash on hand, a substantial majority of which is held domestically. Income and cash flows are largely dependent on oil and gas 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's available but unused committed bank credit was $2.0 billion at December 31, 2011. In October 2011, Occidental entered into a new five-year $2.0 billion bank credit facility (2011 Credit Facility), which replaced its previous $1.4 billion bank credit facility (2006 Credit Facility), which was scheduled to expire in September 2012. The 2011 Credit Facility provides for the termination of loan commitments and requires immediate repayment of any outstanding amounts if certain events of default occur or if Occidental files for bankruptcy. Up to $1.0 billion of the 2011 Credit Facility is available in the form of letters of credit. Occidental did not draw down any amounts under the 2011 Credit Facility or the 2006 Credit Facility during 2011.

The 2011 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 permit the lenders to terminate their commitments or accelerate debt. Borrowings under the 2011 Credit Facility bear interest at various benchmark rates, including LIBOR, plus a margin based on Occidental's senior debt ratings. Additionally, Occidental paid prorated annual facility fees of 0.10 percent and 0.05 percent, respectively, in 2011 on the total commitment amounts of the 2011 Credit Facility and the 2006 Credit Facility based on Occidental’s senior debt ratings.

Occidental has a shelf registration statement that facilitates issuing senior debt securities. In August 2011, Occidental issued $2.15 billion of debt under this shelf, 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 will be payable semiannually in arrears in February and August of each year for both 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.

Occidental, from time to time, may access and has accessed debt markets for long-term and short-term funding for general corporate purposes, including acquisitions. At this time, Occidental does not anticipate any needs for such funding.

As of December 31, 2011, 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.

Cash Flow Analysis

In millions		2011			2010			2009
Net cash provided by operating activities		$	12,281		$	9,566		$	5,946

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

In 2011, 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. In 2011, oil volumes increased, compared to 2010, mainly due to acquisitions in California and the Williston Basin, including the effect of post-acquisition capital investment, and higher production in Oman’s Mukhaizna Field and Iraq, which were partially offset by lower production in Libya. Increases in field support, workover and well maintenance costs in 2011, compared to 2010, partially offset the increases in prices and volumes.

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 oil and NGL 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 most important sources of the increase in operating cash flow in 2010, compared to 2009, were higher worldwide oil and domestic natural gas prices and

volumes. In 2010, compared to 2009, Occidental’s global realized oil and United States natural gas prices for continuing operations each increased by 31 percent. In 2010, Occidental's United States gas production represented approximately 59 percent of its worldwide natural gas production. Occidental’s 2010 oil and gas sales volumes increased, compared to 2009, mainly due to the new production from Bahrain and higher production in the Mukhaizna Field in Oman and higher domestic gas production, partially offset by a decline in Colombia. Increases in field support, workover and well maintenance costs in 2010, compared to 2009, partially offset the increases in prices and volumes.

The increase in operating cash flows in 2010, compared to 2009, also reflected higher chemical product prices for PVC, VCM, ethylene dichloride (EDC) and chlorine, which resulted in higher margins. In addition, all chemical product volumes increased in 2010, compared to 2009, due to improved market conditions, particularly for exports. The 2010 operating cash flows also reflected higher margins in the marketing and trading and gas processing businesses and increased earnings in the pipeline business.

In general, the overall impact of the chemical and midstream and marketing segments’ margins was less significant than the changes in oil and gas segment prices because the chemical and midstream and marketing segments' earnings and cash flows are significantly smaller than those for the oil and gas segment.

Other non-cash charges to income in 2011, 2010 and 2009 included charges for stock-based compensation plans and asset retirement obligation accruals. The 2010 amount included a $275 million charge for asset impairments, predominately of gas properties in the Rocky Mountain region.

Operating cash flows for discontinued operations include the Argentine operations through the date they were sold in February 2011. The 2009 amounts included after-tax charges of $111 million for asset impairments of certain Argentine producing properties.

In millions	2011			2010			2009
Capital expenditures
Oil and Gas	$	(6,145	)	$	(3,166	)	$	(2,448	)
Chemical		(234	)		(237	)		(205	)
Midstream and Marketing		(1,089	)		(501	)		(554	)
Corporate		(50	)		(36	)		(38	)
Total		(7,518	)		(3,940	)		(3,245	)
Other investing activities, net		(4,955	)		(4,940	)		(1,885	)
Net cash used by investing activities – continuing operations		(12,473	)		(8,880	)		(5,130	)
Investing cash flow from discontinued operations		2,570			(415	)		(336	)
Net cash used by investing activities	$	(9,903	)	$	(9,295	)	$	(5,466	)

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.

Occidental’s capital spending for 2012 is expected to be approximately $8.3 billion and will be focused on increasing oil and gas production and ensuring Occidental's returns remain well above its cost of capital given current oil and gas prices and the cost environment.

The increase in capital expenditures in 2012 from $7.5 billion in 2011 will be allocated to the oil and gas segment. Of the $8.3 billion 2012 capital spending, the oil and gas, midstream and marketing, and chemical segments will receive 84 percent, 11 percent and 5 percent, respectively.

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.

The 2009 other investing activities, net amount included $1.7 billion in cash payments for the acquisitions of businesses and assets, including acquisitions of various oil and gas properties in California and the Permian Basin for approximately $610 million, interests in Phibro for approximately $370 million, additional interests in Plains Pipeline for approximately $330 million and various other acquisitions totaling approximately $320 million. The 2009 amount also included foreign signing bonuses of approximately $190 million, the bulk of which was scheduled under the 2008 Libya agreements.

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 and $336 million in 2010 and 2009, respectively.

Commitments at December 31, 2011, for major fixed and determinable capital expenditures during 2012 and thereafter were approximately $2.0 billion. Occidental expects to fund these commitments and capital expenditures with cash from operations.

In millions		2011			2010			2009
Net cash (used) provided by financing activities		$	(1,175	)	$	1,083		$	(1,033	)

The 2011 amount included net proceeds of approximately $2.1 billion from the August 2011 issuance of senior unsecured notes. The 2011 amount also included financing cash flow use of $1.5 billion to retire other long-term debt, purchases of treasury stock of $274 million and $121 million of distributions to a noncontrolling interest partner.

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

The 2009 amount included net proceeds of $740 million from the issuance of 4.125-percent senior unsecured notes due 2016 and Occidental’s payment of $600 million of debt associated with Dolphin Energy.

Occidental also paid common stock dividends of $1.4 billion in 2011, $1.2 billion in 2010 and $1.1 billion in 2009.

Off-Balance-Sheet Arrangements

In the course of its business activities, Occidental pursues a number of projects and transactions to meet its core business objectives. Occidental also makes commitments on behalf of unconsolidated entities. Some of these projects, transactions and commitments (off-balance-sheet arrangements) are not reflected on Occidental’s balance sheets, as a result of the application of generally accepted accounting principles (GAAP) to their specific terms. The following is a description of the business purpose and nature of these 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, 2011, Occidental’s guarantees were not material and a substantial majority consisted of limited recourse guarantees on $300 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. For more information, see "Contractual Obligations."

Contractual Obligations

The table below summarizes and cross-references Occidental’s contractual obligations. This summary indicates those obligations that are reflected in the Consolidated Balance Sheets as of December 31, 2011, as well as those that are not.

			Payments Due by Year
Contractual Obligations (in millions)	Total		2012		2013 and 2014		2015 and 2016		2017 and thereafter
Consolidated Balance Sheet
Long-term debt (Note 5) (a)	$	5,904	$	―	$	600	$	1,450	$	3,854
Other long-term liabilities (b)		2,070		228		459		222		1,161
Other Obligations
Operating leases (Note 6) (c)		1,013		140		187		169		517
Purchase obligations (d,e,f)		7,868		2,657		2,027		759		2,425
Total	$	16,855	$	3,025	$	3,273	$	2,600	$	7,957

(a)	Excludes unamortized debt discount and interest on the debt. As of December 31, 2011, interest on long-term debt totaling $1.5 billion is payable in the following years (in millions): 2012 - $189, 2013 and 2014 - $369, 2015 and 2016 - $326, 2017 and thereafter - $597.
(b)	Includes obligations under postretirement benefit and deferred compensation plans, as well as certain accrued liabilities.
(c)	Amounts have not been reduced for sublease rental income.
(d)	Amounts represent payments which will become due under long-term agreements to purchase goods and services used in the normal course of business. Some of these arrangements involve take-or-pay commitments but they do not represent debt obligations. Long-term purchase contracts are discounted at a 3.2-percent discount rate.
(e)	Amounts exclude certain oil purchase obligations related to marketing and trading activities for which there are no minimum amounts.
(f)	Amounts represent agreements Occidental has entered into providing for future payments to secure terminal and pipeline capacity, drilling rigs and services, electrical power, steam and certain chemical raw materials.

Lawsuits, Claims and Other Contingencies

reserve balances for environmental matters. Reserve balances for other matters as of December 31, 2011 and 2010, were not material to Occidental's consolidated balance sheets. Occidental also evaluates the amount of reasonably possible additional losses that it could incur as a result of the matters mentioned above. Occidental has disclosed its range of reasonably possible 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.

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. While the audits of corporate tax returns for taxable years through 2009 have concluded for United States federal income tax purposes, the 2010 and 2011 taxable years are currently under review by the United States Internal Revenue Service pursuant to its Compliance Assurance Program. 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, 2011, Occidental is not aware of circumstances that it believes would reasonably be expected to lead to future indemnity claims against it in connection with these transactions that would result in payments materially in excess of reserves.

Environmental Liabilities and Expenditures

Occidental’s operations are subject to stringent federal, state, local and foreign laws and regulations relating to improving or maintaining environmental quality. 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, 2011, Occidental participated in or monitored remedial activities or proceedings at 160 sites. The following table presents Occidental’s environmental remediation reserves as of December 31, 2011, 2010 and 2009, 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, as follows:

$ amounts in millions	2011			2010			2009
	# of Sites	Reserve Balance		# of Sites	Reserve Balance		# of Sites	Reserve Balance
NPL sites	36	$	63	38	$	56	39	$	57
Third-party sites	73		88	83		91	81		104
Occidental-operated sites	22		120	20		122	19		126
Closed or non-operated Occidental sites	29		89	29		97	29		116
Total	160	$	360	170	$	366	168	$	403

As of December 31, 2011, Occidental’s environmental reserves exceeded $10 million each at 10 of the 160 sites described above, and 107 of the sites had reserves from zero to $1 million each.

As of December 31, 2011, two landfills in western New York owned by Occidental accounted for 64 percent of its reserves associated with NPL sites. Maxus Energy Corporation has retained the liability and indemnified Occidental for 13 of the remaining NPL sites.

As of December 31, 2011, Maxus has also retained the liability and indemnified Occidental for 9 of the 73 third-party sites. Two of the remaining 64 third-party sites — a former copper mining and smelting operation in Tennessee and a containment and removal project in Tennessee — accounted for 44 percent of Occidental’s reserves associated with these sites.

Four sites — chemical plants in Kansas, Louisiana and New York and a group of oil and gas properties in the southwestern United States — accounted for 61 percent of the reserves associated with the Occidental-operated sites. Two other sites — a former chemical plant in Tennessee and a closed coal mine in Pennsylvania — accounted for 42 percent of the reserves associated with closed or non-operated Occidental sites.

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

In millions	2011			2010			2009
Balance - Beginning of Year	$	366		$	403		$	439
Remediation expenses and interest accretion		53			26			26
Changes from acquisitions/dispositions		14			3			4
Payments		(73	)		(66	)		(66	)
Balance - End of Year	$	360		$	366		$	403

Occidental expects to expend funds corresponding to approximately half of the current environmental reserves over the next four years and the balance over the subsequent 10 or more years. Occidental believes its range of reasonably possible additional loss beyond those liabilities recorded for environmental remediation at the sites described above 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 the years ended December 31:

In millions	2011		2010		2009
Operating Expenses
Oil and Gas	$	158	$	108	$	110
Chemical		68		72		67
Midstream and Marketing		21		13		14
	$	247	$	193	$	191
Capital Expenditures
Oil and Gas	$	110	$	72	$	78
Chemical		15		19		15
Midstream and Marketing		15		13		4
	$	140	$	104	$	97
Remediation Expenses
Corporate	$	52	$	25	$	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 $160 million for 2012.

Foreign Investments

Many of Occidental’s assets are located outside North America. At December 31, 2011, the carrying value of Occidental’s assets in countries outside North America aggregated approximately $11 billion, or approximately 18 percent of Occidental’s total assets at that date. Of such assets, approximately $9 billion are located in the Middle East/North Africa and approximately $1.4 billion are located in Latin America. For the year ended December 31, 2011, net sales outside North America totaled $8.7 billion, or approximately 36 percent of total net sales.

Critical Accounting Policies and Estimates

The process of preparing financial statements in accordance with GAAP requires the management of Occidental to make 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. Occidental considers the following to be its most critical accounting policies and estimates that involve management's judgment. There has been no material change to these policies over the past three years. The selection and development of these critical accounting policies and estimates have been discussed with the Audit Committee of the Board of Directors.

Oil and Gas Properties

The carrying value of Occidental’s property, plant and equipment (PP&E) represents the cost incurred to acquire or develop the asset, including any capitalized interest, net of accumulated depreciation, depletion and amortization (DD&A) and net of any impairment charges. For business acquisitions, PP&E cost is based on fair values at the acquisition date. 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, costs of acquiring properties, costs of drilling successful exploration wells and development costs are capitalized. The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. If proved reserves have been found, the costs of exploratory wells remain capitalized. Otherwise, the costs of the related exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. Occidental's practice is generally to expense 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.

Annual lease rentals and geological, geophysical and seismic costs are expensed as incurred.

Occidental’s policy is to expense the costs of injectants for secondary and tertiary recovery.

Depreciation and depletion of oil and gas producing properties are determined by the unit-of-production method. Leasehold acquisition costs are amortized over total proved reserves, while capitalized development and successful exploration costs are amortized 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 commercial viability 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 2011, revisions of previous estimates provided a net 214 million BOE reduction to proved reserves, which amounted to less than 7 percent of Occidental's total reserves as of December 31, 2011.

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 $0.75 per barrel, which would increase or decrease pre-tax income by $200 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, 2011, the net capitalized costs attributable to unproved properties were $4.9 billion. The unproved amounts are not subject to DD&A or impairment 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 will 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, where 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. For example, if natural gas prices in the United States remain depressed for an extended period, management’s plans for certain domestic gas assets may change and some of its investments may become impaired. Any impairment loss would be calculated as the excess of the asset's net book value over its estimated fair value.

Chemical Assets

Occidental's chemical assets are depreciated using either the unit-of-production or 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 $2.5 billion and its depreciation expense for 2012 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 $40 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 such treatment and management elects to do so. If a derivative does not qualify or is not designated and documented as a cash-flow hedge, 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, 2011.

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.

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, based on the priority of the inputs to the valuation techniques, in a three-level fair value hierarchy: 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:

Trading securities – Quoted prices in active markets exist and are used to provide fair values for these instruments. These securities are classified as Level 1.

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) financial commodity 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, 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.

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 best assumptions regarding expectations of projected cash flows, and discounts the expected cash flows using a risk-adjusted risk-free discount rate.

Environmental Liabilities and Expenditures

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, 2011, 2010 and 2009, 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 loss. 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) the regulatory agency may ultimately reject or modify Occidental’s proposed remedial plan; (4) improved or alternative remediation technologies may change remediation costs; and (5) laws and regulations may impose more or less stringent remediation requirements or affect cost sharing or allocation of liability.

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 adjusts 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 $36 million. If the reserve balance were increased by 10 percent, Occidental would record an additional remediation expense of $36 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 laws or regulations, changes in management’s plans or intentions and the outcome of legal proceedings, settlements or other factors. See "Lawsuits, Claims and Other Contingencies" for additional information.

Significant Accouting and Disclosure Changes

Pursuant to a new rule issued by the Financial Accounting Standards Board, Occidental moved the Consolidated Statements of Comprehensive Income to consecutively follow the Consolidated Statements of Income. Occidental early-adopted the rule, as permitted, in the fourth quarter of 2011.

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 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 vary by $0.50 per Mcf, it would have an estimated annual effect on Occidental's pre-tax income of approximately $125 million. As production levels change in the future, the sensitivity of Occidental’s results to oil and gas prices also will change. The trading and marketing results are also sensitive to price changes of oil, gas and, to a lesser degree, other commodities. These sensitivities are additionally dependent on trading and marketing 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. A variation in ethylene dichloride (EDC) prices of $10 per ton would have a pre-tax annual effect on income of approximately $5 million. Historically, over time, product price changes have tracked raw material and feedstock product price changes, somewhat mitigating the margin effect of price changes. According to Chemical Market Associates, Inc., December 2011 average contract prices were: chlorine—$288 per ton, caustic soda—$615 per ton, PVC—$0.75 per lb. and EDC—$180 per ton.

Marketing and Trading Operations

Through its marketing and trading activities and within its established policy controls and procedures, Occidental uses derivative instruments, including a combination of short-term futures, forwards, options and swaps, to improve realized prices for its oil and gas. 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. In the past, Occidental has also used derivatives to reduce its exposure to price volatility on a small portion of its oil and gas production.

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

As part of its third-party marketing and trading activities, Occidental enters into purchase and sale contracts for oil and gas. Occidental manages these contracts so that the aggregate terms and volumes of the purchases and sales generally approximate each other. The following table shows the changes in the net fair value of Occidental’s marketing and trading derivative contracts during 2011 and 2010:

Assets/(liabilities) (in millions)	2011			2010
Fair value of contracts outstanding at beginning of year	$	(142	)	$	(345	)
Contracts realized or settled during the year		182			(17	)
Gains (losses) or other changes in fair value		(53	)		220
Fair value of contracts outstanding at end of year	$	(13	)	$	(142	)

The following table shows the fair value of derivatives, segregated by maturity periods and by methodology of fair value estimation:

	Maturity Periods
Source of Fair Value Assets/(liabilities) (in millions)		2012			2013 and 2014			2015 and 2016			2017 and thereafter		Total
Prices actively quoted	$	(4	)	$	3		$	―		$	―	$	(1	)
Prices provided by other external sources		71			(62	)		(21	)		―		(12	)
Total	$	67		$	(59	)	$	(21	)	$	―	$	(13	)

Cash-Flow Hedges

Throughout 2011, Occidental held a series of collar agreements that qualified as cash-flow hedges for the sale of approximately 3 percent of its oil production. These agreements were for existing domestic production and terminated as of December 31, 2011. The collar agreements hedged the sale of 12,000 barrels per day at a weighted-average strike price that ranged from $32.92 to $46.27.

In 2009, Occidental entered into financial swap agreements for the sale of a portion of its existing natural gas production from the Rocky Mountain region of the United States that qualify as cash-flow hedges. The following table presents the daily quantities and weighted-average prices that will be received by Occidental as of December 31, 2011:

Natural Gas - Swaps		Daily Volume (cubic feet)		Average Price
January 2012 ― March 2012		50 million		$6.07

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. These derivative agreements continue through January 2013. As of December 31, 2011, Occidental had approximately 25 billion cubic feet of natural gas held in storage. As of December 31, 2011, Occidental had cash-flow hedges for the forecast sale, to be settled by physical delivery, of approximately 35 billion cubic feet of natural gas held in storage.

As of December 31, 2011, the total fair value of cash-flow hedges, which was a net asset of $39 million, was included in the total fair value (a net liability of $13 million) in the tables 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. The marketing and trading value at risk determined with this method was immaterial during 2011.

On December 31, 2009, Occidental acquired Phibro, which trades oil, gas and other commodities. Occidental determined that operations of Phibro are not reasonably likely to have a material adverse effect on the Company. This conclusion is based primarily on the trading limits Occidental placed on the unit, including, among others, limits on total notional trade value, value at risk and credit, as well as the highly liquid positions the operation maintains, as a result of which the market risk typically can be neutralized on short notice.

Delivery Commitments

Occidental sells a portion of its oil, NGLs and natural gas from its operations, as well as volumes from third parties, under a variety of contractual obligations that specify the delivery of a fixed and determinable quantity. The total amount contracted to be delivered from 2012 through 2019, a substantial majority of which are in the

United States, is approximately 107 million barrels of oil, 358 billion cubic feet of gas and immaterial amounts of NGLs. As of December 31, 2011, Occidental had purchase contracts to fulfill a substantial portion of these obligations and believes that it has sufficient production and existing volumes in storage, as well as the ability to fulfill the remaining obligations with contractual purchases, and that, to the extent it has any shortfall in sourcing the required quantities, it believes it has the ability to secure such volumes in the spot market.

Interest Rate Risk

General

Occidental's exposure to changes in interest rates relates primarily to its variable-rate, long-term debt obligations, and is not expected to be material. As of December 31, 2011, variable-rate debt constituted approximately one 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, except rates)	U.S. Dollar Fixed-Rate Debt		U.S. Dollar Variable-Rate Debt		Grand Total (a)
2012	$	―	$	―	$	―
2013		600		―		600
2014		―		―		―
2015		―		―		―
2016		1,450		―		1,450
Thereafter		3,786		68		3,854
Total	$	5,836	$	68	$	5,904
Weighted-average interest rate		3.23%		0.11%		3.20%
Fair Value	$	6,342	$	68	$	6,410

(a)

Excludes unamortized net discounts of $33 million.

Credit Risk

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 agreements are used when appropriate. Occidental monitors aggregated counterparty exposure relative to credit limits. 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 are executed on a daily margin basis. 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, 2011 and 2010, Occidental had a net liability of $58 million and $234 million, respectively, for which the amount of collateral posted was $27 million and $10 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, 2011 and 2010.

As of December 31, 2011, the substantial majority of the credit exposures was with investment grade counterparties. Occidental believes its exposure to credit-related losses at December 31, 2011 was not material. Losses associated with credit risk have been immaterial for all years presented.

Foreign Currency Risk

Occidental’s foreign operations have currency risk. Occidental manages its exposure primarily by balancing monetary assets and liabilities and maintaining cash positions in foreign currencies only at levels necessary for operating purposes. Most international 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, 2011, 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 "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 — Proved Reserves" and " — Industry Outlook," "Chemical Segment — Industry Outlook," "Midstream, Marketing and Other Segment — Industry Outlook," "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 uncertainty of future 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.

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, 2011 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, 2011, 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.

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, 2011 and 2010, and the related consolidated statements of income, stockholders’ equity, comprehensive income and cash flows for each of the years in the three-year period ended December 31, 2011. 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, 2011 and 2010, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2011, 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, 2011, 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 23, 2012 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/ KPMG LLP

Los Angeles, California

February 23, 2012

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, 2011, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Assessment of and Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

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

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

In our opinion, Occidental Petroleum Corporation and its subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, 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, 2011 and 2010, and the related consolidated statements of income, stockholders’ equity, comprehensive income and cash flows for each of the years in the three-year period ended December 31, 2011, and our report dated February 23, 2012 expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

Los Angeles, California

February 23, 2012

Consolidated Balance Sheets	Occidental Petroleum Corporation
In millions	and Subsidiaries

Assets at December 31,	2011			2010

current assets

Cash and cash equivalents	$	3,781		$	2,578

Trade receivables, net of reserves of $16 in 2011 and $19 in 2010		5,395			5,032

Marketing and trading assets and other		916			900

Assets of discontinued operations		―			2,861

Inventories		1,069			1,041

Prepaid expenses and other		381			647

Total current assets		11,542			13,059

investments in unconsolidated entities		2,072			2,039

property, plant and equipment

Oil and gas segment		56,682			46,232

Chemical segment		5,715			5,508

Midstream, marketing and other segment		5,664			4,094

Corporate		1,310			1,123

		69,371			56,957

Accumulated depreciation, depletion and amortization		(23,687	)		(20,421	)

		45,684			36,536

long-term receivables and other assets, net		746			798

TOTAL ASSETS	$	60,044		$	52,432

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

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

Liabilities and Stockholders’ Equity at December 31,	2011			2010

current liabilities

Accounts payable	$	5,304		$	4,646

Accrued liabilities		2,440			2,397

Domestic and foreign income taxes		110			170

Liabilities of discontinued operations		93			612

Total current liabilities		7,947			7,825

long-term debt, net		5,871			5,111

deferred credits and other liabilities

Deferred and other domestic and foreign income taxes		4,846			3,445

Long-term liabilities of discontinued operations		98			115

Other		3,662			3,452

		8,606			7,012

contingent liabilities and commitments

stockholders’ equity

Common stock, $0.20 par value, authorized 1.1 billion shares, outstanding shares: 2011 — 886,808,654 and 2010 — 885,275,302		177			177

Treasury stock: 2011 — 75,799,573 shares and 2010 — 72,480,538 shares		(4,502	)		(4,228	)

Additional paid-in capital		7,286			7,191

Retained earnings		35,142			29,868

Accumulated other comprehensive loss		(483	)		(524	)

Total stockholders’ equity		37,620			32,484

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	60,044		$	52,432

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

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

For the years ended December 31,	2011			2010			2009

revenues and other income
Net sales	$	23,939		$	19,045		$	14,814
Interest, dividends and other income		165			111			118
Gains on disposition of assets, net		15			1			10
		24,119			19,157			14,942

costs and other deductions
Cost of sales (excludes depreciation, depletion and amortization of $3,584 in 2011, $3,145 in 2010 and $2,643 in 2009)		7,385			6,112			5,105
Selling, general and administrative and other operating expenses		1,523			1,396			1,300
Depreciation, depletion and amortization		3,591			3,153			2,687
Taxes other than on income		605			484			425
Exploration expense		258			262			254
Charges for impairments		―			275			―
Interest and debt expense, net		298			116			133
		13,660			11,798			9,904

income before income taxes and other items		10,459			7,359			5,038
Provision for domestic and foreign income taxes		4,201			2,995			2,063
Income from equity investments		(382	)		(277	)		(227	)

income from continuing operations		6,640			4,641			3,202
Discontinued operations, net		131			(39	)		(236	)

net income		6,771			4,602			2,966
Less: Net income attributable to noncontrolling interest		―			(72	)		(51	)
net income attributable to common stock	$	6,771		$	4,530		$	2,915

basic earnings per common share (attributable to common stock)
Income from continuing operations	$	8.16		$	5.62		$	3.88
Discontinued operations, net		0.16			(0.05	)		(0.29	)
basic earnings per common share	$	8.32		$	5.57		$	3.59

diluted earnings per common share (attributable to common stock)
Income from continuing operations	$	8.16		$	5.61		$	3.87
Discontinued operations, net		0.16			(0.05	)		(0.29	)

diluted earnings per common share	$	8.32		$	5.56		$	3.58

dividends per common share	$	1.84		$	1.47		$	1.31
The accompanying notes are an integral part of these consolidated financial statements.

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

For the years ended December 31,	2011			2010			2009
Net income attributable to common stock	$	6,771		$	4,530		$	2,915
Other comprehensive income (loss) items:
Foreign currency translation adjustments		(11	)		4			32
Unrealized gains (losses) on derivatives (a)		14			37			(93	)
Pension and postretirement adjustments (b)		(60	)		(52	)		1
Reclassification of realized losses on derivatives and securities (c)		98			83			13
Unrealized gains on securities (d)		―			―			3
Other comprehensive income (loss), net of tax (e)		41			72			(44	)
Comprehensive income attributable to common stock	$	6,812		$	4,602		$	2,871

(a)	Net of tax of $(7), $(20) and $53 in 2011, 2010 and 2009, respectively.
(b)	Net of tax of $34, $30 and zero in 2011, 2010 and 2009, respectively.
(c)	Net of tax of $(56), $(47) and $(7) in 2011 2010 and 2009, respectively.
(d)	Net of tax of zero, zero and $(1) in 2011, 2010 and 2009, respectively.
(e)	There were no other comprehensive income (loss) items related to noncontrolling interests in 2011, 2010 and 2009.

Consolidated Statements of Stockholders' Equity
In millions

	Equity Attributable to Common Stock
											Accumulated
						Additional					Other
	Common		Treasury			Paid-in		Retained			Comprehensive			Noncontrolling			Total
	Stock		Stock			Capital		Earnings			Income (Loss)			Interest			Equity
Balance, December 31, 2008	$	176	$	(4,121	)	$	7,113	$	24,684		$	(552	)	$	25		$	27,325
Net income		―		―			―		2,915			―			51			2,966
Other comprehensive loss, net of tax		―		―			―		―			(44	)		―			(44	)
Dividends on common stock		―		―			―		(1,065	)		―			(16	)		(1,081	)
Issuance of common stock and other, net		1		―			14		―			―			18			33
Purchases of treasury stock		―		(40	)		―		―			―			―			(40	)
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		―			―			(150	)(a)		(86	)
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

(a)

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

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

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

For the years ended December 31,	2011			2010			2009

cash flow from operating activities
Net income	$	6,771		$	4,602		$	2,966
Adjustments to reconcile net income to net cash provided by operating activities:
Discontinued operations, net		(131	)		39			236
Depreciation, depletion and amortization of assets		3,591			3,153			2,687
Deferred income tax provision		1,436			406			659
Other noncash charges to income		205			507			336
Gains on disposition of assets, net		(15	)		(1	)		(10	)
Undistributed earnings from equity investments		(33	)		(60	)		(88	)
Dry hole and impairment expense		160			139			200
Changes in operating assets and liabilities:
(Increase) decrease in receivables		(338	)		(850	)		(573	)
(Increase) decrease in inventories		(50	)		(42	)		(119	)
Decrease (increase) in prepaid expenses and other assets		73			131			(9	)
Increase (decrease) in accounts payable and accrued liabilities		829			1,295			(316	)
(Decrease) increase in current domestic and foreign income taxes		(174	)		186			1
Other operating, net		(18	)		(149	)		(114	)
Operating cash flow from continuing operations		12,306			9,356			5,856
Operating cash flow from discontinued operations, net of taxes		(25	)		210			90
Net cash provided by operating activities		12,281			9,566			5,946

cash flow from investing activities
Capital expenditures		(7,518	)		(3,940	)		(3,245	)
Payments for purchases of assets and businesses		(4,909	)		(4,924	)		(1,782	)
Sales of assets, net		50			20			51
Other, net		(96	)		(36	)		(154	)
Investing cash flow from continuing operations		(12,473	)		(8,880	)		(5,130	)
Investing cash flow from discontinued operations		2,570			(415	)		(336	)
Net cash used by investing activities		(9,903	)		(9,295	)		(5,466	)

cash flow from financing activities
Proceeds from long-term debt		2,111			2,584			740
Payments of long-term debt		(1,523	)		(311	)		(692	)
Proceeds from issuance of common stock		50			10			18
Purchases of treasury stock		(274	)		(67	)		(40	)
Distributions to noncontrolling interest		(121	)		―			(16	)
Cash dividends paid		(1,436	)		(1,159	)		(1,063	)
Other, net		18			26			27
Financing cash flow from continuing operations		(1,175	)		1,083			(1,026	)
Financing cash flow from discontinued operations		―			―			(7	)
Net cash provided (used) by financing activities		(1,175	)		1,083			(1,033	)

Increase (decrease) in cash and cash equivalents		1,203			1,354			(553	)
Cash and cash equivalents — beginning of year		2,578			1,224			1,777

Cash and cash equivalents — end of year	$	3,781		$	2,578		$	1,224

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

Notes to Consolidated Financial Statements	Occidental Petroleum Corporation
	and Subsidiaries

Note 1

Summary of Significant Accounting Policies

Nature of Operations

In this report, "Occidental" or "the Company" refers to Occidental Petroleum Corporation, a Delaware corporation (OPC), or OPC and one or more entities in which it owns a controlling interest (subsidiaries). Occidental is a multinational organization whose subsidiaries and affiliates operate in the oil and gas, chemical and midstream, marketing and other 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, treats, processes, transports, stores, purchases and markets oil, condensate, NGLs, natural gas, carbon dioxide (CO2) and power. It also trades around its assets, including pipelines and storage capacity, and trades oil, NGLs, gas and other commodities.

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 2011 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 majority voting 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, where 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. Such estimates primarily relate to unsettled transactions and events as of the date of the consolidated financial statements. 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 assumptions provide a reasonable basis for the fair presentation of Occidental’s financial position and results of operations.

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 in jurisdictions where such assets originate and reversal of temporary differences.

The accompanying consolidated financial statements include assets of approximately $11 billion as of December 31, 2011, and net sales of approximately $8.7 billion for the year ended December 31, 2011, relating to Occidental’s operations in countries outside North America. Occidental operates some of its oil and gas business in countries that occasionally have experienced political instability, armed conflict, 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 financial affairs so as to mitigate its exposure to such risks and would seek compensation in the event of nationalization.

Since Occidental’s major products are commodities, significant changes in the prices of oil and gas and chemical products may have a significant impact on Occidental’s results of operations.

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 $3.5 billion and $2.5 billion at December 31, 2011 and 2010, 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 the lower of weighted-average cost or market and are reviewed periodically for obsolescence. Oil, NGLs and natural gas inventories are valued at the lower of cost or market.

For the chemical segment, Occidental's 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 following table summarizes the activity of capitalized exploratory well costs for continuing operations for the years ended December 31:

In millions	2011			2010			2009
Balance — Beginning of Year	$	73		$	51		$	63
Additions to capitalized exploratory well costs pending the determination of proved reserves		155			73			51
Reclassifications to property, plant and equipment based on the determination of proved reserves		(28	)		(29	)		(8	)
Capitalized exploratory well costs charged to expense		(18	)		(22	)		(55	)
Balance — End of Year	$	182		$	73		$	51

Annual lease rentals and geological, geophysical and seismic costs are expensed as incurred.

Occidental’s policy is to expense the costs of injectants for secondary and tertiary recovery.

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, where 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 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.

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

Fair Values - Recurring

	Ø	Trading securities – Quoted prices in active markets exist and are used to provide fair values for these instruments. These securities are classified as Level 1.
	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) financial commodity 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, 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.

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 best assumptions regarding expectations of projected cash flows, and discounts the expected cash flows using a risk-adjusted risk-free discount rate.

Accrued Liabilities—Current

Accrued liabilities include accrued payroll, commissions and related expenses of $462 million and $470 million at December 31, 2011 and 2010, 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 loss, 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, 2011, 2010 and 2009, Occidental did not have any accruals for reimbursements or recoveries.

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 risk-free rate of interest. 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 initial capitalized cost is depreciated over the useful life of the asset. Occidental has recorded no market risk premium in its liability since no reliable estimate can be made at this time.

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 $1,030 million and $762 million is included in deferred credits and other liabilities - other, with the remaining current portion in accrued liabilities at December 31, 2011 and 2010, respectively.

For the years ended December 31, (in millions)	2011			2010
Beginning balance	$	800		$	657
Liabilities incurred - capitalized to PP&E		74			47
Liabilities settled and paid		(53	)		(32	)
Accretion expense		48			37
Acquisitions and other - capitalized to PP&E		177			66
Revisions to estimated cash flows - capitalized to PP&E		43			25
Ending balance	$	1,089		$	800

Derivative Instruments

Stock-Based Incentive Plans

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

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 stock options (Options), stock-settled stock appreciation rights (SARs), performance stock awards (PSAs) and total shareholder return incentives (TSRIs), compensation value is initially measured on the grant date using potential exercise values or estimated payout levels using Monte Carlo or other valuation models. Compensation expense for all awards 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 PSAs and TSRIs is adjusted quarterly for any changes in the number of shares expected to be issued based on the performance criteria using valuation models. In addition, every quarter, compensation expense for the cash-settled portion of RSUs, SARs, PSAs and TSRIs is adjusted for changes in the value of the underlying stock. The stock-settled portion of all these awards is expensed using the initially measured compensation value. All such performance or stock-price-related changes are recognized in periodic compensation expense.

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 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 Plans and Postretirement Benefits

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 uses the fair value of assets to determine expected return on plan assets in calculating pension expense. Occidental funds and expenses negotiated pension increases for domestic union employees over the terms of the applicable collective bargaining agreements.

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. Some of the collateral Occidental receives for securities loaned includes investments in short-term investment funds. The 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 $2.9 billion, $2.4 billion and $1.4 billion during the years ended December 31, 2011, 2010 and 2009, respectively. Occidental also paid production, property and other taxes of approximately $635 million, $510 million and $484 million during the years ended December 31, 2011, 2010 and 2009, respectively, substantially all of which was in the United States. Additionally, net payments for income taxes related to discontinued operations were zero, $42 million and $4 million for the years 2011, 2010 and 2009, respectively. Production, property and other taxes paid related to discontinued operations were zero, $197 million and $100 million for the years 2011, 2010 and 2009, respectively. Interest paid totaled approximately $315 million, $161 million and $164 million for the years 2011, 2010 and 2009, 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. Exchange-rate gains and losses for continuing operations were not material for all years presented.

Note 2

Acquisitions, Dispositions and Other Transactions

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, initiated in 2010.

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, mid-continent 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 for the year ended December 31, 2011. Net revenues and pre-tax losses for such discontinued operations were, respectively, $700 million and $(39) million in 2010, and $589 million and $(369) million in 2009. As of December 31, 2011 and 2010, the assets of discontinued operations related to Argentina were zero and $2.9 billion, respectively, which mainly comprised PP&E as of December 31, 2010. As of December 31, 2011 and 2010, the liabilities of discontinued operations were zero and $513 million, which mainly comprised deferred tax liabilities and accrued liabilities as of December 31, 2010.

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 approximately 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 its partners signed a 20-year contract with the South Oil Company of Iraq to develop the Zubair Field in Iraq.

2009

On December 31, 2009, Occidental completed the acquisition of Phibro LLC (Phibro) for approximately $370 million in cash and maintains a controlling interest. Phibro, primarily an investor in commodities, is included as a part of Occidental's midstream and marketing segment. The assets acquired and liabilities assumed were recorded at their estimated fair values at the acquisition date. No goodwill was recorded on this transaction.

In December 2009, Occidental purchased additional noncontrolling interests in Plains Pipeline for approximately $330 million in cash.

Occidental and its partners signed a Development and Production Sharing Agreement (DPSA) in April 2009 with the National Oil and Gas Authority of Bahrain for further development of the Bahrain Field, which became effective in December 2009. Under this agreement, a joint operating company formed by Occidental and its partners serves as operator for the project.

In 2009, Occidental acquired various additional oil and gas properties in California and the Permian Basin for approximately $610 million in cash.

Note 3

Accounting and Disclosure Changes

Recently Adopted Accounting and Disclosure Changes

Pursuant to a new rule issued by the Financial Accounting Standards Board, Occidental moved the Consolidated Statements of Comprehensive Income to consecutively follow the Consolidated Statements of Income. Occidental early adopted the rule, as permitted, in the fourth quarter of 2011.

Note 4

Inventories

Net carrying values of inventories valued under the LIFO method were approximately $176 million and $177 million at December 31, 2011 and 2010, respectively. Inventories in continuing operations consisted of the following:

Balance at December 31, (in millions)	2011			2010
Raw materials	$	69		$	63
Materials and supplies		443			414
Finished goods		655			636
		1,167			1,113
LIFO reserve		(98	)		(72	)
Total	$	1,069		$	1,041

Note 5

Long-term Debt

Long-term debt consisted of the following:


Balance at December 31, (in millions)	2011			2010
4.10% senior notes due 2021	$	1,300		$	1,300
1.75% senior notes due 2017		1,250			―
7.0% senior notes due 2013		―			1,000
3.125% senior notes due 2022		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
6.75% senior notes due 2012		―			368
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 (0.11% and 0.32% as of December 31, 2011 and 2010, respectively)		68			68
8.75% medium-term notes due 2023		22			22
		5,904			5,122
Less:
Unamortized discount, net		(33	)		(11	)
Total	$	5,871		$	5,111

Occidental's available but unused committed bank credit was $2.0 billion at December 31, 2011. In October 2011, Occidental entered into a new five-year, $2.0 billion bank credit facility (2011 Credit Facility) which replaced its previous $1.4 billion bank credit facility (2006 Credit Facility), which was scheduled to expire in September 2012. The 2011 Credit Facility provides for the termination of the loan commitments and requires immediate repayment of any outstanding amounts if certain events of default occur or if Occidental files for bankruptcy. Up to $1.0 billion of the 2011 Credit Facility is available in the form of letters of credit. Occidental did not draw down any amounts under the 2011 Credit Facility or the 2006 Credit Facility during 2011.

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 will be payable semi-annually in arrears in February and August of each year for both series of notes.

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 will be 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.

In July 2009, Occidental repaid its $600 million debt associated with Dolphin Energy's debt. Also, in July 2009, Dolphin Energy refinanced its debt on a limited-recourse basis. Occidental provided guarantees limited to certain political and other events. At December 31, 2011 and 2010, Occidental’s guarantees were not material and a substantial majority of the amounts consisted of limited recourse guarantees on $300 million of Dolphin’s debt, of which the fair value was immaterial.

At December 31, 2011, minimum principal payments on long-term debt subsequent to December 31, 2011 aggregated $5.9 billion, of which zero is due in 2012, $0.6 billion in 2013, zero in 2014, zero in 2015, $1.5 billion in 2016 and $3.8 billion in 2017 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, 2011 and 2010 were approximately $6.4 billion and $5.5 billion, respectively, compared to carrying values of approximately $5.9 billion and $5.1 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, 2011 and 2010, variable-rate debt constituted approximately one 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, 2011, 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)
2012	$	140
2013		102
2014		85
2015		91
2016		78
Thereafter		517
Total minimum lease payments	$	1,013

(a)

These amounts are net of sublease rentals of $11 million, which are to be received as follows (in millions): 2012—$4, 2013—$4, 2014—$3, 2015—zero and 2016—zero.

Rental expense for operating leases, net of sublease rental income for continuing operations, was $179 million in 2011, $170 million in 2010 and $170 million in 2009. Rental expense was net of sublease income of $4 million, $4 million and $4 million in 2011, 2010 and 2009, respectively.

Note 7

Derivatives

Objective & Strategy

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

Cash-Flow Hedges

Throughout 2011 and 2010, Occidental held a series of collar agreements that qualified as cash-flow hedges for the sale of approximately 3 percent and 2 percent, respectively, of its oil production. These agreements were for existing domestic production and terminated as of December 31, 2011. The collar agreements hedged the sale of 12,000 barrels per day at a weighted-average strike price that ranged from $32.92 to $46.35.

Natural Gas Swaps		Daily Volume (cubic feet)			Average Price
January 2012 - March 2012 (a)		50 million			$6.07

(a)	At December 31, 2010, these contracts were outstanding with the same daily volumes and terms indicated and also covered the period from January 1, 2011 to December 31, 2011.

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. These derivative agreements continue through January 2013. As of December 31, 2011 and 2010, Occidental had approximately 25 billion cubic feet and 28 billion cubic feet of natural gas held in storage, respectively. As of December 31, 2011 and 2010, Occidental had cash-flow hedges for the forecast sale, to be settled by physical delivery, of approximately 35 billion cubic feet and 24 billion cubic feet of natural gas held in storage, respectively.

The following table presents the pre-tax gains and losses recognized in, and reclassified from, AOCI and recognized in income (net sales), including any hedge ineffectiveness, for derivative instruments classified as cash-flow hedges for the years ended December 31, 2011 and 2010 (in millions):

	2011		2010
Commodity Contracts – cash-flow hedges
Unrealized gains recognized in AOCI	$	20	$	55
Losses reclassified into income	$	154	$	123
Gains recognized in income - ineffective portion	$	1	$	2

The following table summarizes net after-tax derivative activity recorded in AOCI for the years ended December 31, 2011 and 2010 (in millions):

	2011			2010
Beginning Balance - AOCI	$	(111	)	$	(227	)
Unrealized gains recognized in AOCI		14			37
Losses reclassified into income		98			79
Ending Balance - AOCI	$	1		$	(111	)

During the next twelve months, Occidental expects that approximately $14 million of net after-tax derivative gains included in AOCI will be reclassified into income based on their valuation as of December 31, 2011.

Derivatives Not Designated as Hedging Instruments

Occidental’s third-party marketing and trading activities focus on purchasing oil, NGLs and gas for resale from partners, producers and third parties whose oil and gas supply is located near its midstream and marketing assets, such as pipelines, processing plants and storage facilities. These purchases allow Occidental to aggregate volumes to maximize prices received for Occidental’s production. The third-party marketing and trading purchase and sales contracts generally approximate each other with respect to aggregate volumes and terms. In addition, Occidental’s Phibro trading unit's strategy is to profit from market price changes using derivatives not designated as hedging instruments.

The following table presents gross volumes of Occidental’s outstanding commodity derivatives contracts not designated as hedging instruments as of December 31, 2011 and 2010:

Commodity	Volumes
	2011	2010
Sales contracts related to Occidental's production
Oil (million barrels)	9	8

Third-party marketing and trading activities
Purchase contracts
Oil (million barrels)	109	136
Natural gas (billion cubic feet)	481	833
Precious metals (million troy ounces)	4	13

Sales contracts
Oil (million barrels)	109	144
Natural gas (billion cubic feet)	723	1,156
Precious metals (million troy ounces)	1	1

In addition, Occidental’s Phibro trading unit has certain other commodity trading contracts, including agricultural products, metals and electricity, as well as foreign exchange contracts, but these were not material to Occidental as of December 31, 2011 and 2010.

Occidental has oil sales contracts representing a small portion of Occidental's domestic oil production. Additionally, for third-party marketing and trading activities, a substantial portion of the sales contracts that exist at the end of a reporting period are typically fulfilled by offsetting purchase contracts that have substantially identical terms entered into within a short time. For a substantial portion of the sales commitments not satisfied by such contracts as of December 31, 2011, Occidental entered into offsetting contracts after December 31, 2011. Occidental believes it has the ability to fulfill any remaining portion through its equity production or through additional third-party purchases.

Approximately $1 million and $293 million of gains from derivatives not designated as hedging instruments were recognized in net sales for the years ended December 31, 2011 and 2010, respectively.

Fair Value of Derivatives

The following tables present the gross fair value of Occidental’s outstanding derivatives as of December 31, 2011 and 2010 (in millions):

	Asset Derivatives	Fair			Liability Derivatives	Fair
December 31, 2011	Balance Sheet Location	Value			Balance Sheet Location	Value
Cash-flow hedges (a)
	Marketing and trading assets and other	$	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)
	Marketing and trading assets and other	$	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 (b)			(755	)			(779	)
Total net fair value of derivatives		$	195			$	184

	Asset Derivatives	Fair			Liability Derivatives	Fair
December 31, 2010	Balance Sheet Location	Value			Balance Sheet Location	Value
Cash-flow hedges (a)
	Marketing and trading assets and other	$	51		Accrued liabilities	$	209
Commodity contracts	Long-term receivables and other assets, net		9		Deferred credits and other liabilities		―
		$	60			$	209

Derivatives not designated as hedging instruments (a)
	Marketing and trading assets and other	$	829		Accrued liabilities	$	823
Commodity contracts	Long-term receivables and other assets, net		86		Deferred credits and other liabilities		85
			915				908
Total gross fair value			975				1,117
Less: counterparty netting and cash collateral (c)			(680	)			(736	)
Total net fair value of derivatives		$	295			$	381

(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, 2011, collateral received of $39 million has been netted against derivative assets and collateral paid of $63 million has been netted against derivative liabilities.
(c)	As of December 31, 2010, collateral received of $39 million has been netted against derivative assets and collateral paid of $95 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 are executed on a daily margin basis. Collateral of $173 million and $154 million deposited by Occidental for such contracts with clearing houses and brokers, which has not been reflected in the derivative fair value tables, is included in the marketing and trading assets and other balance as of December 31, 2011 and 2010, 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.

Foreign Currency Risk

Note 8

Environmental Liabilities and Expenditures

Environmental Remediation

As of December 31, 2011, Occidental participated in or monitored remedial activities or proceedings at 160 sites. The following table presents Occidental’s environmental remediation reserves as of December 31, 2011, 2010 and 2009, the current portion of which is included in accrued liabilities ($79 million in 2011, $79 million in 2010 and $84 million in 2009) and the remainder in deferred credits and other liabilities — other ($281 million in 2011, $287 million in 2010 and $319 million in 2009). The reserves are grouped as environmental remediation sites listed or proposed for listing by the U.S. Environmental Protection Agency on the CERCLA NPL (NPL sites) and three categories of non-NPL sites — third-party sites, Occidental-operated sites and closed or non-operated Occidental sites, as follows:

$ amounts in millions	2011			2010			2009
	Number of Sites	Reserve Balance		Number of Sites	Reserve Balance		Number of Sites	Reserve Balance
NPL sites	36	$	63	38	$	56	39	$	57
Third-party sites	73		88	83		91	81		104
Occidental-operated sites	22		120	20		122	19		126
Closed or non-operated Occidental sites	29		89	29		97	29		116
Total	160	$	360	170	$	366	168	$	403

As of December 31, 2011, Occidental’s environmental reserves exceeded $10 million each at 10 of the 160 sites described above, and 107 of the sites had reserves from zero to $1 million each.

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

In millions	2011			2010			2009
Balance — Beginning of Year	$	366		$	403		$	439
Remediation expenses and interest accretion		53			26			26
Changes from acquisitions/dispositions		14			3			4
Payments		(73	)		(66	)		(66	)
Balance — End of Year	$	360		$	366		$	403

Environmental Costs

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

In millions	2011		2010		2009
Operating Expenses
Oil and Gas	$	158	$	108	$	110
Chemical		68		72		67
Midstream and Marketing		21		13		14
	$	247	$	193	$	191
Capital Expenditures
Oil and Gas	$	110	$	72	$	78
Chemical		15		19		15
Midstream and Marketing		15		13		4
	$	140	$	104	$	97
Remediation Expenses
Corporate	$	52	$	25	$	25

Note 9

Lawsuits, Claims, Commitments and Other Contingencies

OPC or certain of its subsidiaries are named, 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, punitive damages, civil penalties or other losses, or injunctive or declaratory relief. OPC or certain of its subsidiaries also have been named in proceedings under CERCLA and similar federal, state, local and foreign environmental laws. These environmental proceedings seek funding or performance of remediation and, in some cases, compensation for alleged property damage, punitive damages, civil penalties and injunctive relief; however, Occidental or such subsidiaries are usually among many companies in these proceedings and have to date been successful in sharing response costs with other financially sound companies. 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, 2011 and 2010, 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. While the audits of corporate tax returns for taxable years through 2009 have concluded for United States federal income tax purposes, the 2010 and 2011 taxable years are currently under review by the United States Internal Revenue Service pursuant to its Compliance Assurance Program. 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, 2011, total purchase obligations were $7.9 billion, which included approximately $2.7 billion, $1.3 billion, $700 million, $450 million and $300 million that will be paid in 2012, 2013, 2014, 2015 and 2016, respectively. Included in the purchase obligations are commitments for major fixed and determinable capital expenditures during 2012 and thereafter, which were approximately $2.0 billion.

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
2011	$	4,806	$	6,035	$	10,841
2010	$	3,295	$	4,269	$	7,564
2009	$	2,091	$	3,123	$	5,214

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

For the years ended December 31, (in millions)	U.S. Federal		State and Local		Foreign		Total
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
2009
Current	$	16	$	27	$	1,361	$	1,404
Deferred		606		37		16		659
	$	622	$	64	$	1,377	$	2,063

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

For the years ended December 31,	2011		2010		2009
United States federal statutory tax rate	35	%	35	%	35	%
Operations outside the United States	4		5		5
State income taxes, net of federal benefit	1		1		1
Other	(1	)	(1	)	(1	)
Tax rate provided by Occidental	39	%	40	%	40	%

The tax effects of temporary differences resulting in deferred income taxes at December 31, 2011 and 2010 were as follows:

		2011					2010
	Deferred			Deferred		Deferred			Deferred
Tax effects of temporary differences (in millions)	Tax Assets			Tax Liabilities		Tax Assets			Tax Liabilities
Property, plant and equipment differences	$	―		$	6,039	$	―		$	4,558
Equity investments, partnerships and foreign subsidiaries		―			351		―			208
Environmental reserves		131			―		135			―
Postretirement benefit accruals		410			―		368			―
Deferred compensation and benefits		286			―		275			―
Asset retirement obligations		318			―		242			―
Foreign tax credit carryforwards		1,240			―		718			―
Federal benefit of state income taxes		104			―		88			―
All other		374			116		442			131
Subtotal		2,863			6,506		2,268			4,897
Valuation allowance		(1,003	)		―		(486	)		―
Total deferred taxes	$	1,860		$	6,506	$	1,782		$	4,897

Included in total deferred tax assets was a current portion aggregating $200 million and $330 million as of December 31, 2011 and 2010, respectively, that was reported in prepaid expenses and other. Total deferred tax assets were $1.9 billion and $1.8 billion as of December 31, 2011 and 2010, 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 has, as of December 31, 2011, foreign tax credit carryforwards of $1.2 billion, which expire in varying amounts through 2021, 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 $5.5 billion at December 31, 2011, 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 $88 million would be required, assuming utilization of available foreign tax credits.

Discontinued operations include income tax charges of $86 million in 2011, and income tax benefits of $26 million in 2010 and $147 million in 2009.

Additional paid-in capital was credited $14 million in 2011, $22 million in 2010 and $24 million in 2009 for an excess tax benefit from the exercise of certain stock-based compensation awards.

As of December 31, 2011, Occidental had liabilities for unrecognized tax benefits of approximately $67 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)	2011			2010
Balance at January 1,	$	38		$	52
Additions based on tax positions related to the current year		44			24
Reductions based on tax positions related to prior years and settlements		(15	)		(38	)
Balance at December 31,	$	67		$	38

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, 2011, 2010 and 2009.

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, 2008		881,423
Issued		1,697
Options exercised and other, net		523
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

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 2011, Occidental purchased 2.7 million shares under the program at an average cost of $77.12 per share.

Additionally, Occidental purchased shares from the trustee of its defined contribution savings plan during the years ended December 31, 2011, 2010 and 2009.

As of December 31, 2011, 2010 and 2009, treasury stock shares numbered 75.8 million, 72.5 million and 71.7 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, 2011, 2010 and 2009, 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	2011			2010			2009
Basic EPS
Income from continuing operations	$	6,640		$	4,641		$	3,202
Less: Income from continuing operations attributable to noncontrolling interest		―			(72	)		(51	)
Income from continuing operations attributable to common stock		6,640			4,569			3,151
Discontinued operations, net		131			(39	)		(236	)
Net income attributable to common stock		6,771			4,530			2,915
Less: Net income allocated to participating securities		(11	)		(6	)		(4	)
Net income attributable to common stock, net of participating securities	$	6,760		$	4,524		$	2,911
Weighted average number of basic shares		812.1			812.5			811.3
Basic EPS	$	8.32		$	5.57		$	3.59

Diluted EPS
Net income attributable to common stock, net of participating securities	$	6,760		$	4,524		$	2,911
Weighted average number of basic shares		812.1			812.5			811.3
Dilutive effect of potentially dilutive securities		0.8			1.3			2.5
Total diluted weighted average common shares		812.9			813.8			813.8
Diluted EPS	$	8.32		$	5.56		$	3.58

Accumulated Other Comprehensive Loss

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

Balance at December 31, (in millions)	2011			2010
Foreign currency translation adjustments	$	(9	)	$	2
Unrealized gains (losses) on derivatives		1			(111	)
Pension and post-retirement adjustments (a)		(475	)		(415	)
Total	$	(483	)	$	(524	)

(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, Options, SARs, PSAs and TSRIs. An aggregate of 66 million shares of Occidental common stock were authorized for issuance and approximately 14 million shares have been issued through December 31, 2011. Of the remaining shares, depending on the type of award granted, approximately 8.8 to 26.3 million shares are available for grants of future awards. During 2011, non-employee directors were granted awards for 64,800 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)	2011		2010		2009
Compensation expense	$	110	$	136	$	151
Income tax benefit recognized in the income statement	$	40	$	50	$	55
Intrinsic value of options and stock-settled SARs exercised	$	21	$	74	$	58
Cash paid (a)	$	124	$	97	$	50
Fair value of PSAs, RSUs and TSRIs vested during the year (b)	$	53	$	19	$	142

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

As of December 31, 2011, there was $193 million of pre-tax unrecognized compensation expense, based on year-end valuation, related to all unvested stock-based incentive award grants. This expense is expected to be recognized over a weighted-average period of 2.0 years.

RSUs

Certain employees are awarded the right to receive cash-settled RSUs, which are equivalent in value to actual shares of Occidental common stock but are paid in cash at the time of vesting. These awards vest either in total over two years or ratably over three years after the grant date and can be forfeited or accelerated under certain conditions. For those awards which vest in total over two years, dividend equivalents are accumulated during the vesting period and are paid when they vest. For those awards which vest ratably, dividend equivalents are paid during the vesting period. The weighted-average, grant-date fair values of these awards granted in 2011, 2010 and 2009 were $104.74, $77.14 and $66.43 per share, respectively.

Certain employees are awarded the right to receive stock-settled RSUs that vest at the end of, or ratably over, three years from the grant date (some vesting may extend to 7 years under certain circumstances) and can be forfeited or accelerated under certain conditions. Dividends or dividend equivalents are paid during the vesting period. The weighted-average, grant-date fair value of the stock-settled RSUs granted in 2011 and 2010 was $102.97 and $84.29, respectively. There were no such awards granted in 2009.

A summary of changes in Occidental’s unvested cash- and stock-settled RSUs during the year ended December 31, 2011 is presented below:

	Cash-Settled				Stock-Settled
			Weighted-Average				Weighted-Average
	RSUs		Grant-Date		RSUs		Grant-Date
	(000's)		Fair Value		(000's)		Fair Value
Unvested at January 1	1,137		$	73.44	310		$	84.18
Granted	717		$	104.74	274		$	102.97
Vested	(518	)	$	73.68	(4	)	$	74.88
Forfeitures	(64	)	$	82.83	(12	)	$	92.04
Unvested at December 31	1,272		$	90.50	568		$	93.14

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 due to subsequent events.

The following is a summary of Option and SAR transactions during the year ended December 31, 2011:

	Cash-Settled							Stock-Settled
					Weighted-							Weighted-
			Weighted-		Average	Aggregate				Weighted-		Average	Aggregate
			Average		Remaining	Intrinsic		SARs &		Average		Remaining	Intrinsic
	SARs		Exercise		Contractual	Value		Options		Exercise		Contractual	Value
	(000's)		Price		Term (yrs)	(000’s)		(000's)		Price		Term (yrs)	(000’s)
Beginning balance, January 1	837		$	24.66				1,014		$	23.62
Exercised	(273	)	$	24.66				(232	)	$	14.44
Ending balance, December 31	564		$	24.66	2.5	$	38,939	782		$	26.34	2.3	$	52,689
Exercisable at December 31	564		$	24.66	2.5	$	38,939	782		$	26.34	2.3	$	52,689

Performance-Based Awards

PSAs and TSRIs

Certain executives are awarded PSAs and 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 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 have payouts that ranged from 0 to 150 percent of the target award that would settle, once certified, equally in stock and cash. TSRIs granted in January 2007 had payouts of 150 percent of the target award and were certified and settled equally in stock and cash in 2011. PSAs granted in January 2007 had payouts of approximately 193 percent of the target award and were certified after year-end 2010 for settlement equally in stock and cash. Dividend equivalents for PSA and TSRI target shares are paid during the performance period regardless of the payout range or settlement provision, except for the TSRIs issued in 2010 and 2011, for which cumulative dividends will be paid upon vesting for the number of vested shares.

The fair values of PSAs and 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 due to subsequent events.

The grant-date assumptions used in the Monte Carlo simulation models for the estimated payout level of TSRIs were as follows:

	TSRIs
Year Granted	2011	2010	2009
Assumptions used:
Risk-free interest rate	0.6%	0.6%	2.1%
Dividend yield	1.8%	1.8%	2.0%
Volatility factor	33%	32%	28%
Expected life (years)	3	3	4
Grant-date fair value of underlying Occidental common stock	$ 102.97	$ 84.29	$ 66.74

A summary of Occidental’s unvested PSAs and TSRIs as of December 31, 2011 and changes during the year ended December 31, 2011 is presented below:

	PSAs				TSRIs
			Weighted-Average				Weighted-Average
	Awards (000’s)		Grant-Date Fair Value of Occidental Stock		Awards (000’s)		Grant-Date Fair Value of Occidental Stock
Unvested at January 1 (a)	143		$	48.83	2,041		$	70.84
Granted (a)	―		$	―	325		$	102.97
Vested (b)	(143	)	$	48.83	(485	)	$	61.93
Forfeitures	―		$	―	(16	)	$	80.14
Unvested at December 31 (a)	―		$	―	1,865		$	78.67

(a)	Unvested awards and award grants are presented at the target or mid-point payouts.
(b)	The payout at vesting was 193 percent and 150 percent of the target for PSAs and TSRIs, respectively.

Note 13

Retirement Plans and Postretirement Benefits

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

Defined Contribution Plans

All domestic employees and certain foreign national employees are eligible to participate in one or more of the defined contribution retirement or savings plans that provide for periodic contributions by Occidental based on plan-specific criteria, such as base pay, age level and employee contributions. Certain salaried employees participate in a supplemental retirement plan that restores benefits lost due to governmental limitations on qualified retirement benefits. The accrued liabilities for the supplemental retirement plan were $126 million and $109 million as of December 31, 2011 and 2010, respectively, and Occidental expensed $110 million in 2011, $101 million in 2010 and $97 million in 2009 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.

Other Postretirement Benefit Plans

Occidental provides medical and dental benefits and life insurance coverage for certain active, retired and disabled employees and their eligible dependents. Occidental generally funds the benefits as they are paid during the year. The total benefit costs, including the postretirement costs, were approximately $194 million in 2011, $180 million in 2010 and $158 million in 2009.

Obligations and Funded Status

The following table shows the funding status of Occidental's plans:

	Pension Benefits						Postretirement Benefits
							Unfunded Plans						Funded Plans
For the years ended December 31, (in millions)	2011			2010			2011			2010			2011			2010
Changes in benefit obligation:
Benefit obligation — beginning of year	$	624		$	573		$	940		$	848		$	51		$	43
Service cost — benefits earned during the period		12			16			21			18			1			1
Interest cost on projected benefit obligation		29			30			43			42			2			2
Actuarial loss		49			42			67			92			14			6
Foreign currency exchange rate (gain) loss		(5	)		10			―			―			―			―
Benefits paid		(51	)		(47	)		(46	)		(60	)		(1	)		(1	)
Settlements		(57	)		―			―			―			―			―
Benefit obligation — end of year	$	601		$	624		$	1,025		$	940		$	67		$	51
Changes in plan assets:
Fair value of plan assets — beginning of year	$	495		$	482		$	―		$	―		$	1		$	2
Actual return on plan assets		13			44			―			―			―			―
Foreign currency exchange rate gain (loss)		(3	)		1			―			―			―			―
Employer contributions		79			15			―			―			―			―
Settlements		(57	)		―			―			―			―			―
Benefits paid		(51	)		(47	)		―			―			―			(1	)
Fair value of plan assets — end of year	$	476		$	495		$	―		$	―		$	1		$	1
Unfunded status:	$	(125	)	$	(129	)	$	(1,025	)	$	(940	)	$	(66	)	$	(50	)

The projected benefit obligation, accumulated benefit obligation and fair value of plan assets for defined benefit pension plans with an accumulated benefit obligation in excess of plan assets were $370 million, $343 million and $227 million, respectively, as of December 31, 2011, and $259 million, $234 million and $82 million, respectively, as of December 31, 2010. The projected benefit obligation, accumulated benefit obligation and fair value of plan assets for defined benefit pension plans with plan assets in excess of the accumulated benefit obligation were $231 million, $226 million and $250 million, respectively, as of December 31, 2011, and $365 million, $360 million and $413 million, respectively, as of December 31, 2010.

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

Amounts recognized in the consolidated balance sheets consist of:

	Pension Benefits						Postretirement Benefits
							Unfunded Plans						Funded Plans
As of December 31, (in millions)	2011			2010			2011			2010			2011			2010
Other assets	$	24		$	53		$	―		$	―		$	―		$	―
Accrued liabilities		(5	)		(7	)		(47	)		(60	)		―			―
Deferred credits and other liabilities — other		(144	)		(175	)		(978	)		(880	)		(66	)		(50	)
	$	(125	)	$	(129	)	$	(1,025	)	$	(940	)	$	(66	)	$	(50	)

At December 31, 2011 and 2010, AOCI included the following after-tax balances:

	Pension Benefits				Postretirement Benefits
					Unfunded Plans				Funded Plans
As of December 31, (in millions)	2011		2010		2011		2010		2011		2010
Net loss	$	146	$	111	$	309	$	284	$	22	$	15
Prior service cost		2		2		2		3		―		―
	$	148	$	113	$	311	$	287	$	22	$	15

Occidental does not expect any plan assets to be returned during 2012.

Components of Net Periodic Benefit Cost

The following table sets forth the components of net periodic benefit costs:

	Pension Benefits									Postretirement Benefits
										Unfunded Plans						Funded Plans
For the years ended December 31, (in millions)	2011			2010			2009			2011		2010		2009		2011		2010		2009
Net periodic benefit costs:
Service cost — benefits earned during the period	$	12		$	16		$	14		$	21	$	18	$	16	$	1	$	1	$	1
Interest cost on benefit obligation		29			30			28			43		42		39		2		2		2
Expected return on plan assets		(33	)		(31	)		(25	)		―		―		―		―		―		―
Amortization of prior service cost		1			1			1			1		1		1		―		―		―
Recognized actuarial loss		13			15			17			29		26		20		2		1		1
Additional settlement cost		2			―			―			―		―		―		―		―		―
Currency adjustments		(3	)		9			12			―		―		―		―		―		―
Net periodic benefit cost	$	21		$	40		$	47		$	94	$	87	$	76	$	5	$	4	$	4

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 $19 million and $1 million, 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 $34 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
					Unfunded Plans				Funded Plans
For the years ended December 31,	2011		2010		2011		2010		2011		2010
Benefit Obligation Assumptions:
Discount rate	4.12	%	4.74	%	4.12	%	4.74	%	4.12	%	4.74	%
Rate of compensation increase	4.00	%	4.00	%	―		―		―		―

Net Periodic Benefit Cost Assumptions:
Discount rate	4.74	%	5.12	%	4.74	%	5.12	%	4.74	%	5.12	%
Assumed long term rate of return on assets	6.50	%	6.50	%	―		―		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 2011 and the Hewitt Bond Universe yield curve in 2010. 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, 2011 and 2010. The average rate of increase in future compensation levels ranged from a low of 1.5 percent to a high of 10.0 percent in 2011, depending on local economic conditions. The expected long-term rate of return on plan assets was 5.8 percent and 6.8 percent in excess of local inflation in 2011 and 2010, 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 health care cost trend rates projected at an assumed Consumer Price Index (CPI) increase of 2.04 percent and 2.54 percent as of December 31, 2011 and 2010, respectively. Beginning in 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, the health care cost trend rates were projected at annual rates ranging ratably from 9.0 percent in 2011 to 6.0 percent through the year 2017 and thereafter. A 1-percent increase or a 1-percent decrease in these assumed health care cost trend rates would result in an increase of $40 million or a reduction of $36 million, respectively, in the postretirement benefit obligation as of December 31, 2011, and a corresponding increase of $4 million or a reduction of $3 million in interest cost in 2011. The annual service costs would not be materially affected by these changes.

The actuarial assumptions used could change in the near term as a result of changes in expected future trends and other factors that, depending on the nature of the changes, could cause increases or decreases in the plan liabilities.

Fair Value of Pension and Postretirement 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, 2011 Using
Description	Level 1			Level 2			Level 3			Total
Asset Class:
Collateral received for securities loaned		$	―		$	1		$	―		$	1
U.S. government securities			22			―			―			22
Corporate bonds (a)			―			83			―			83
Common/collective trusts (b)			―			14			―			14
Mutual funds:
Bond funds			84			―			―			84
Value funds			77			―			―			77
Blend and growth funds			25			―			―			25
Common and preferred stocks (c)			131			―			―			131
Other			―			33			12			45
Total pension plan assets (d)		$	339		$	131		$	12		$	482

	Fair Value Measurements at December 31, 2010 Using
Description	Level 1			Level 2			Level 3			Total
Asset Class:
Cash and cash equivalents		$	1		$	―		$	―		$	1
Collateral received for securities loaned			―			4			―			4
U.S. government securities			23			―			―			23
Corporate bonds (a)			―			70			―			70
Common/collective trusts (b)			―			42			―			42
Mutual funds:
Bond funds			81			―			―			81
Value funds			89			―			―			89
Blend and growth funds			39			―			―			39
Common and preferred stocks (c)			120			―			―			120
Other			―			29			17			46
Total pension plan assets (d)		$	353		$	145		$	17		$	515

(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 investment in U.S. and non-U.S. common and preferred stocks from diverse industries.
(d)	Amounts exclude net payables of approximately $6 million and $20 million as of December 31, 2011 and 2010, respectively.

The activity during the years ended December 31, 2011 and 2010 for the assets using Level 3 fair value measurements was not significant.

Occidental expects to contribute $6 million to its defined benefit pension plans during 2012. All of the contributions are expected to be in the form of cash.

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

For the years ended December 31, (in millions)	Pension Benefits			Postretirement Benefits
2012		$	46		$	50
2013		$	46		$	50
2014		$	47		$	51
2015		$	43		$	52
2016		$	48		$	54
2017 — 2021		$	231		$	294

Note 14

Investments and Related-Party Transactions

As of December 31, 2011 and 2010, investments in unconsolidated entities comprised $2.1 billion and $2 billion of equity-method investments, respectively.

Equity Investments

As of December 31, 2011, Occidental’s equity investments consisted mainly of a 24.5-percent interest in the stock of Dolphin Energy, an approximately 35-percent interest in the General Partner of Plains Pipeline and various other partnerships and joint ventures. Equity investments paid dividends of $349 million, $217 million and $139 million to Occidental in 2011, 2010 and 2009, respectively. As of December 31, 2011, cumulative undistributed earnings of equity-method investees since their respective acquisitions were $400 million. As of December 31, 2011, Occidental's investments in equity investees exceeded the underlying equity in net assets by $1.1 billion, of which $1 billion represents goodwill and $134 million relates to assets, including intangibles, which are being 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)	2011		2010		2009
Revenues	$	2,439	$	1,759	$	1,080
Costs and expenses		2,046		1,482		853
Net income	$	393	$	277	$	227

As of December 31, (in millions)	2011		2010
Current assets	$	2,230	$	2,041
Non-current assets	$	4,381	$	3,965
Current liabilities	$	1,532	$	1,323
Long-term debt	$	2,305	$	2,454
Other non-current liabilities	$	168	$	119
Stockholders’ equity	$	2,606	$	2,110

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 a DPSA 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.

In Ecuador, Occidental has a 14-percent interest in the Oleoducto de Crudos Pesados Ltd. (OCP) oil export pipeline, which Occidental records 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 purchases power, steam and chemicals from and sells oil, NGLs, gas, chemicals and power to certain of its equity investees at market-related prices. During 2011, 2010 and 2009, Occidental entered into the following related-party transactions and had the following amounts due from or to its related parties:

December 31, (in millions)	2011		2010		2009
Purchases (a)	$	10	$	153	$	138
Sales (b)	$	392	$	440	$	291
Services	$	10	$	2	$	2
Advances and amounts due from	$	32	$	135	$	123
Amounts due to	$	21	$	383	$	112

(a)	In 2010 and 2009, purchases from EHP accounted for 90 percent and 92 percent, respectively.
(b)	In 2011, sales to Dolphin Energy accounted for 16 percent. In 2010 and 2009, sales to EHP and Dolphin Energy accounted for 44 percent and 63 percent, respectively. In 2011, 2010 and 2009, sales of Occidental-produced oil and NGLs to Plains Pipeline accounted for 76 percent, 50 percent and 26 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.

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, 2011 and 2010 (in millions):

	Fair Value Measurements at December 31, 2011 Using
Description	Level 1		Level 2		Level 3		Netting and Collateral			(a)	Total Fair Value
Assets:
Commodity derivatives	$	310	$	640	$	―	$	(755	)		$	195
Total assets	$	310	$	640	$	―	$	(755	)		$	195

Liabilities:
Commodity derivatives	$	311	$	652	$	―	$	(779	)		$	184
Total liabilities	$	311	$	652	$	―	$	(779	)		$	184

	Fair Value Measurements at December 31, 2010 Using
Description	Level 1		Level 2		Level 3		Netting and Collateral			(a)	Total Fair Value
Assets:
Trading equity securities - natural resources industry	$	116	$	―	$	―	$	―			$	116
Trading U.S. treasury securities		10		―		―		―				10
Commodity derivatives		178		797		―		(680	)			295
Total Assets	$	304	$	797	$	―	$	(680	)		$	421

Liabilities:
Commodity derivatives	$	201	$	916	$	―	$	(736	)		$	381
Total liabilities	$	201	$	916	$	―	$	(736	)		$	381

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

Fair Values - Nonrecurring

In 2010, Occidental recorded an impairment charge of $275 million predominantly to write off gas properties in the Rocky Mountain region.

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, marketing and other (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, treats, processes, transports, stores, purchases and markets oil, condensate, NGLs, natural gas, CO2 and power. It also trades around its assets, including pipelines and storage capacity, and trades oil, NGLs, gas and other commodities.

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 approximately equal to 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, Marketing and Other			Corporate and Eliminations			Total
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)	$	10,841	(d)
Income taxes		―			―			―			(4,201	) (g)		(4,201	)
Discontinued operations, net		―			―			―			131			131
Net income (loss) attributable to common stock	$	10,241	(d)	$	861		$	448		$	(4,779	) (h)	$	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)	$	7,564	(d,e)
Income taxes		―			―			―			(2,995	) (g)		(2,995	)
Discontinued operations, net		―			―			―			(39	)		(39	)
Net income (loss) attributable to common stock	$	7,151	(d,e)	$	438		$	472		$	(3,531	) (h)	$	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
YEAR ENDED DECEMBER 31, 2009
Net sales	$	11,009	(a)	$	3,225	(b)	$	1,016	(c)	$	(436	)	$	14,814
Pretax operating profit (loss)	$	5,097	(d,e)	$	389		$	235		$	(507	) (f)	$	5,214	(d,e)
Income taxes		―			―			―			(2,063	) (g)		(2,063	)
Discontinued operations, net		―			―			―			(236	)		(236	)
Net income (loss) attributable to common stock	$	5,097	(d,e)	$	389		$	235		$	(2,806	) (h)	$	2,915	(e)
Investments in unconsolidated entities	$	118		$	131		$	1,473		$	10		$	1,732
Property, plant and equipment additions, net (i)	$	2,571		$	213		$	583		$	39		$	3,406
Depreciation, depletion and amortization	$	2,258		$	298		$	110		$	21		$	2,687
Total assets	$	26,854		$	3,608		$	8,773		$	4,994	(j)	$	44,229
(See footnotes on next page)

Footnotes:
(a)	Oil sales represented approximately 87 percent, 86 percent and 86 percent of the oil and gas segment net sales for the years ended December 31, 2011, 2010 and 2009, respectively.
(b)	Total product sales for the chemical segment comprised the following:

	Basic Chemicals		Vinyls		Other Chemicals
Year ended December 31, 2011	58	%	39	%	3	%
Year ended December 31, 2010	57	%	40	%	3	%
Year ended December 31, 2009	63	%	34	%	3	%

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

	Gas Processing		Power
	Gas Processing		Power		Marketing, Trading, Transportation and other
Year ended December 31, 2011	64	%	27	%	9	%
Year ended December 31, 2010	52	%	27	%	21	%
Year ended December 31, 2009	56	%	26	%	18	%

(d)	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 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. The 2009 amount includes an $8 million pre-tax charge for the termination of rig contracts.
(e)	Includes amounts attributable to common stock after deducting noncontrolling interest amounts of $72 million and $51 million for 2010 and 2009, respectively.
(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)		2011			2010			2009
corporate
Pre-tax operating profit (loss)
Premium on debt extinguishments	$	(163	)	$	―		$	―
Severance charge		―			―			(40	)
Railcar leases		―			―			(15	)
	$	(163	)	$	―		$	(55	)
Income taxes
State income tax charge	$	(33	)	$	―		$	―
Foreign tax credit carryforwards		―			80			―
Tax effect of pre-tax adjustments *		50			100			22
	$	17		$	180		$	22

Discontinued operations, net of tax **	$	131		$	(39	)	$	(236	)

*	Amounts represent the tax effect of all pre-tax adjustments listed, as well as those in footnote (d).
**	The 2011 amount includes a $144 million after-tax gain from the sale of the Argentine operations. The 2009 amount includes an after-tax charge of $111 million for asset impairments of certain Argentine producing properties.

(i)	Includes capital expenditures, capitalized interest, and for 2009, capitalized CO2, and excludes purchases of assets, net. Also includes amounts attributable to the noncontrolling interest in a Colombian subsidiary for 2010 and 2009.
(j)	Includes Argentine assets held for sale for 2010 and 2009.

Geographic Areas

In millions

	Net sales (a)						Property, plant and equipment, net
For the years ended December 31,	2011		2010		2009		2011		2010		2009
United States	$	15,040	$	12,151	$	9,448	$	36,283	$	28,571	$	23,440
Foreign
Qatar		3,432		2,677		2,201		2,735		2,823		2,842
Oman		2,500		1,666		1,038		2,143		1,967		1,885
Colombia		1,054		999		922		854		715		688
Yemen		907		766		667		245		347		398
United Arab Emirates		187		100		8		1,448		223		151
Libya		151		373		243		926		953		968
Other Foreign		668		313		287		1,050		937		765
Total Foreign		8,899		6,894		5,366		9,401		7,965		7,697
Total	$	23,939	$	19,045	$	14,814	$	45,684	$	36,536	$	31,137

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

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

Three months ended	March 31			June 30			September 30			December 31
Segment net sales
Oil and gas	$	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.

2010 Quarterly Financial Data (Unaudited)	Occidental Petroleum Corporation
In millions, except per-share amounts	and Subsidiaries

Three months ended	March 31			June 30			September 30			December 31
Segment net sales
Oil and gas	$	3,491		$	3,518		$	3,508		$	3,759
Chemical		956			1,013			1,051			996
Midstream, marketing and other		369			236			388			478
Eliminations		(200	)		(164	)		(184	)		(170	)

Net sales	$	4,616		$	4,603		$	4,763		$	5,063


Gross profit	$	2,222		$	2,186		$	2,330		$	2,566


Segment earnings
Oil and gas (a)	$	1,861		$	1,867		$	1,757		$	1,666	(b)
Chemical		30			108			189			111
Midstream, marketing and other		94			13			163			202
		1,985			1,988			2,109			1,979

Unallocated corporate items
Interest expense, net		(35	)		(20	)		(18	)		(20	)
Income taxes		(746	)		(809	)		(822	)		(618	)(c)
Other		(107	)		(82	)		(66	)		(149	)

Income from continuing operations (a)		1,097			1,077			1,203			1,192
Discontinued operations, net		(33	)		(14	)		(12	)		20
Net income attributable to common stock	$	1,064		$	1,063		$	1,191		$	1,212

Basic earnings per common share (a)
Income from continuing operations	$	1.35		$	1.32		$	1.48		$	1.47
Discontinued operations, net		(0.04	)		(0.01	)		(0.02	)		0.02
Basic earnings per common share	$	1.31		$	1.31		$	1.46		$	1.49


Diluted earnings per common share (a)
Income from continuing operations	$	1.35		$	1.32		$	1.48		$	1.47
Discontinued operations, net		(0.04	)		(0.01	)		(0.02	)		0.02
Diluted earnings per common share	$	1.31		$	1.31		$	1.46		$	1.49


Dividends per common share	$	0.33		$	0.38		$	0.38		$	0.38


Market price per common share
High	$	84.54		$	89.99		$	82.92		$	99.03
Low	$	76.01		$	77.15		$	72.23		$	78.63

(a)	Represent amounts attributable to common stock after deducting noncontrolling interest amounts.
(b)	Includes a fourth quarter pre-tax charge of $275 million for asset impairments, predominantly of gas properties in the Rocky Mountain region.
(c)	Includes a fourth quarter benefit of $80 million related to foreign tax credit carryforwards.

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 and condensate, NGLs and natural gas and changes in such quantities. Reserves are stated after applicable royalties. Estimated reserves include Occidental's economic interests under production sharing contracts (PSCs) and other similar economic arrangements.

Effective beginning the year ended December 31, 2009, the U.S. Securities and Exchange Commission (SEC) and the Financial Accounting Standards Board modified certain disclosure requirements for oil and gas properties. Occidental adopted these requirements as of December 31, 2009. As a result, proved oil, NGLs and gas reserves are now calculated using the unweighted arithmetic average of the first-day-of-the-month price for each month within the year instead of the year-end market price. For the 2011, 2010 and 2009 disclosures, the West Texas Intermediate oil prices used were $96.19 per barrel, $79.43 per barrel and $61.18 per barrel, respectively. The Henry Hub gas prices used for the 2011, 2010 and 2009 disclosures were $4.04 per MMBtu, $4.39 per MMBtu and $3.99 per MMBtu, respectively. Occidental does not have any reserves from non-traditional sources. The adoption of the new requirements did not have a material effect on Occidental's proved reserves.

Prior to December 31, 2009, Occidental’s production volumes and reserves had been reported as a mix of pre-tax and after-tax volumes while its revenues reflected pre-tax sales. This difference was caused by Occidental’s PSCs in the Middle East/North Africa where production is immediately taken and sold to pay the local income tax. Occidental had historically reported these volumes as additional revenues and income taxes but not additional production and reserves. To simplify Occidental’s reporting and to conform with industry practice, Occidental included these volumes in its reserves as of December 31, 2009. Beginning in 2010, Occidental’s production volumes match revenues reported. For ease of comparison, prior year data for daily production volumes and for results per unit of production computations are shown using pre-tax amounts.

Oil Reserves
In millions of barrels (MMbbl)
	United States		Latin America	(a,b)	Middle East/ North Africa	(c)	Total
proved developed and undeveloped reserves
Balance at December 31, 2008	1,355		89		383		1,827
Revisions of previous estimates	35		(4	)	97		128
Improved recovery	47		25		51		123
Extensions and discoveries	16		2		―		18
Purchases of proved reserves	13		―		11		24
Sales of proved reserves	―		―		―		―
Production	(81	)	(17	)	(48	)	(146	)
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
proved developed reserves
December 31, 2008	1,070		62		284		1,416
December 31, 2009	1,131		71		378		1,580
December 31, 2010	1,126		69		366		1,561
December 31, 2011 (e)	1,146		69		317		1,532
proved undeveloped reserves
December 31, 2008	285		27		99		411
December 31, 2009	254		24		116		394
December 31, 2010	334		21		96		451
December 31, 2011 (f)	380		27		69		476

(a)	Proved reserves as of December 31, 2009 and 2008 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 and 2011 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, 108 MMbbl and 135 MMbbl as of December 31, 2010, 2009 and 2008, respectively. The Argentine proved developed and proved undeveloped reserves were 91 MMbbl and 75 MMbbl, 58 MMbbl and 50 MMbbl and 62 MMbbl and 73 MMbbl as of December 31, 2010, 2009 and 2008, respectively.
(c)	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 10 percent of the proved developed reserves at December 31, 2011 are nonproducing, the majority of which are located in the United States and Libya.
(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 de minimis.

NGL Reserves
In millions of barrels (MMbbl)
	United States		Latin America	Middle East/ North Africa	(a)	Total
proved developed and undeveloped reserves
Balance at December 31, 2008	192		―	61		253
Revisions of previous estimates	23		―	11		34
Improved recovery	9		―	―		9
Extensions and discoveries	13		―	―		13
Purchases of proved reserves	2		―	―		2
Sales of proved reserves	―		―	―		―
Production	(18	)	―	(4	)	(22	)
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
proved developed reserves
December 31, 2008	139		―	61		200
December 31, 2009	155		―	68		223
December 31, 2010	163		―	61		224
December 31, 2011 (b)	165		―	55		220
proved undeveloped reserves
December 31, 2008	53		―	―		53
December 31, 2009	66		―	―		66
December 31, 2010	74		―	―		74
December 31, 2011 (c)	60		―	―		60

(a)	Proved reserve amounts relate to PSCs and other similar economic arrangements.
(b)	Approximately 6 percent of the proved developed reserves at December 31, 2011 are nonproducing, the majority of which are located in the United States and Libya.
(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 de minimis.

Gas Reserves
In billions of cubic feet (Bcf)
	United States		Latin America	(a)	Middle East/ North Africa	(b)	Total
proved developed and undeveloped reserves
Balance at December 31, 2008	3,153		63		1,236		4,452
Revisions of previous estimates	(688	)	(6	)	281		(413	)
Improved recovery	137		2		11		150
Extensions and discoveries	362		―		―		362
Purchases of proved reserves	67		―		736		803
Sales of proved reserves	―		―		―		―
Production	(232	)	(6	)	(89	)	(327	)
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
proved developed reserves
December 31, 2008	1,866		60		1,206		3,132
December 31, 2009	1,931		51		1,759		3,741
December 31, 2010	2,007		50		1,665		3,722
December 31, 2011 (c)	2,365		32		1,555		3,952
proved undeveloped reserves
December 31, 2008	1,287		3		30		1,320
December 31, 2009	868		2		416		1,286
December 31, 2010	1,027		6		383		1,416
December 31, 2011 (d)	1,000		1		370		1,371

(a)	Excludes proved natural gas reserves from the Argentine operations sold in February 2011 and classified as discontinued operations of 182 Bcf, 130 Bcf and 149 Bcf as of December 31, 2010, 2009 and 2008, respectively. The Argentine proved developed and proved undeveloped reserves were 108 Bcf and 74 Bcf, 74 Bcf and 56 Bcf and 82 Bcf and 67 Bcf as of December 31, 2010, 2009 and 2008, respectively.
(b)	Proved reserve amounts relate to PSCs and other similar economic arrangements.
(c)	Approximately 2 percent of the proved developed reserves at December 31, 2011 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 de minimis.

Total Reserves
In millions of BOE (MMBOE) (a)
	United States		Latin America	(b,c)	Middle East/ North Africa	(d)	Total
proved developed and undeveloped reserves
Balance at December 31, 2008	2,073		99		650		2,822
Revisions of previous estimates	(57	)	(5	)	154		92
Improved recovery	78		26		53		157
Extensions and discoveries	89		2		―		91
Purchases of proved reserves	26		―		134		160
Sales of proved reserves	―		―		―		―
Production	(137	)	(18	)	(67	)	(222	)
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
proved developed reserves
December 31, 2008	1,520		71		546		2,137
December 31, 2009	1,608		80		739		2,427
December 31, 2010	1,624		78		705		2,407
December 31, 2011 (f)	1,707		74		631		2,412
proved undeveloped reserves
December 31, 2008	553		28		104		685
December 31, 2009	464		24		185		673
December 31, 2010	579		22		159		760
December 31, 2011 (g)	606		27		131		764

(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.
(b)	Proved reserves as of December 31, 2009 and 2008 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, 130 MMBOE and 160 MMBOE as of December 31, 2010, 2009 and 2008, respectively. The Argentine proved developed and proved undeveloped reserves were 109 MMBOE and 87 MMBOE, 70 MMBOE and 60 MMBOE and 76 MMBOE and 84 MMBOE as of December 31, 2010, 2009 and 2008, respectively.
(d)	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 7 percent of the proved developed reserves at December 31, 2011 are nonproducing, the majority of which are located in the United States and Libya.
(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 de minimis.

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

In millions	United States			Latin America		(a)	Middle East/ North Africa			Total
december 31, 2011
Proved properties	$	36,123		$	1,861		$	13,839		$	51,823
Unproved properties (b)		4,675			―			184			4,859

Total capitalized costs (c)		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 (b)		3,474			5			190			3,669

Total capitalized costs (c)		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		$	6,461		$	29,901
december 31, 2009
Proved properties	$	24,488		$	1,900		$	10,909		$	37,297
Unproved properties (b)		1,709			―			158			1,867

Total capitalized costs (c)		26,197			1,900			11,067			39,164
Accumulated depreciation, depletion and amortization		(7,956	)		(1,154	)		(4,826	)		(13,936	)

Net capitalized costs	$	18,241		$	746		$	6,241		$	25,228

(a)	Includes net capitalized cost of $31 million as of December 31, 2009, related to the noncontrolling interest in a Colombian subsidiary. Excludes Argentine capitalized costs of $2.6 billion and $2.5 billion as of December 31, 2010 and 2009, respectively.
(b)	The 2011, 2010 and 2009 amounts primarily consist of Midcontinent and Other, Permian, California and Libya.
(c)	Includes costs related to leases, exploration costs, lease and well equipment, other equipment, capitalized interest, asset retirement obligations and other costs.

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

In millions	United States		Latin America		(a)	Middle East/ North Africa		Total
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		$	1,420	$	7,836
for the year ended december 31, 2009
Property acquisition costs
Proved properties	$	569	$	―		$	158	$	727
Unproved properties		100		―			3		103
Exploration costs		131		4			50		185
Development costs		1,223		229			996		2,448
Costs incurred	$	2,023	$	233		$	1,207	$	3,463

(a)

Includes exploration and development costs of $2 million and $5 million and $0 and $13 million in 2010 and 2009, respectively, related to the noncontrolling interest in a Colombian subsidiary. The 2010 and 2009 amounts exclude Argentine costs incurred of $448 million and $353 million, respectively.

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:

In millions	United States		Latin America		(a,b)	Middle East/ North Africa		Total
for the year ended december 31, 2011
Revenues (c)	$	9,933	$	1,113		$	7,373	$	18,419
Production costs (d)		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(e)		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 (c)	$	7,578	$	1,046		$	5,621	$	14,245
Production costs (d)		1,757		167			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
Charges for impairments		275		―			―		275
Exploration expenses		158		7			97		262
Pretax income		3,090		717			3,484		7,291
Income tax expense(e)		929		227			1,689		2,845
Results of operations	$	2,161	$	490		$	1,795	$	4,446
for the year ended december 31, 2009
Revenues (c)	$	5,832	$	957		$	4,195	$	10,984
Production costs (d)		1,452		161			601		2,214
Other operating expenses		389		31			208		628
Depreciation, depletion and amortization		1,237		198			823		2,258
Taxes other than on income		399		14			―		413
Exploration expenses		156		15			83		254
Pretax income		2,199		538			2,480		5,217
Income tax expense(e)		594		151			1,227		1,972
Results of operations	$	1,605	$	387		$	1,253	$	3,245

(a)	Includes revenues of $129 million and $118 million, production costs of $17 million and $17 million, and results of operations of $72 million and $49 million in 2010 and 2009, respectively, related to the noncontrolling interest in a Colombian subsidiary.
(b)	Excludes amounts from the Argentine operations sold in February 2011 and classified as discontinued operations.
(c)	Revenues from net production exclude royalty payments and other adjustments.
(d)	Production costs are the costs incurred in lifting the oil and gas to the surface and include gathering, treating, 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.
(e)	United States federal income taxes reflect certain expenses related to oil and gas activities allocated for United States income tax purposes only, including allocated interest and corporate overhead.

Results per Unit of Production for Continuing Operations

	United States		Latin America		(a,b)	Middle East/ North Africa		Total		(c)
for the year ended december 31, 2011
Revenues from net production barrel of oil equivalent ($/bbl.) (d,e)	$	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 (f)		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
Revenues from net production barrel of oil equivalent ($/bbl.) (d,e)	$	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
Charges for impairments		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 (f)		6.64		15.91			16.37		11.05
Results of operations	$	15.44	$	34.35		$	17.40	$	17.27
for the year ended december 31, 2009
Revenues from net production barrel of oil equivalent ($/bbl.) (d,e)	$	42.47	$	54.65		$	45.40	$	44.43
Production costs		10.57		9.19			6.50		8.95
Other operating expenses		2.83		1.77			2.25		2.54
Depreciation, depletion and amortization		9.01		11.31			8.91		9.13
Taxes other than on income		2.91		0.80			―		1.67
Exploration expenses		1.14		0.86			0.90		1.03
Pretax income		16.01		30.72			26.84		21.11
Income tax expense (f)		4.33		8.62			13.28		7.98
Results of operations	$	11.68	$	22.10		$	13.56	$	13.13

(a)	Includes the noncontrolling interest in a Colombian subsidiary for 2010 and 2009.
(b)	Excludes amounts from the Argentine operations sold in February 2011 and classified as discontinued operations.
(c)	Results per unit of production is calculated using the volumes produced from continuing operations.
(d)	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.
(e)	Revenues from net production exclude royalty payments and other adjustments.
(f)	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.

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, 2011, 2010 and 2009, 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 each of December 31, 2011, 2010 and 2009. 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.

Standardized Measure of Discounted Future Net Cash Flows
In millions
	United States			Latin America		(a)	Middle East/ North Africa			Total
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 (b)		(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 (b)		(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
at december 31, 2009
Future cash inflows	$	96,997		$	5,439		$	32,344		$	134,780
Future costs
Production costs and other operating expenses		(42,352	)		(2,261	)		(7,605	)		(52,218	)
Development costs (b)		(7,895	)		(386	)		(3,305	)		(11,586	)
Future income tax expense		(13,386	)		(677	)		(10,010	)		(24,073	)
Future net cash flows		33,364			2,115			11,424			46,903
Ten percent discount factor		(18,348	)		(701	)		(4,009	)		(23,058	)
		15,016			1,414			7,415			23,845
Less: net cash flows attributable to noncontrolling interests		―			(89	)		―			(89	)
Standardized measure of discounted future net cash flows	$	15,016		$	1,325		$	7,415		$	23,756

(a)	Excludes Argentine future net cash flows of $1.7 billion and $1.2 billion as of December 31, 2010 and 2009, respectively.
(b)	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,		2011			2010			2009
Beginning of year	$	32,737		$	23,756		$	15,482
Sales and transfers of oil and gas produced, net of production costs and other operating expenses		(15,243	)		(11,698	)		(7,535	)
Net change in prices received per barrel, net of production costs and other operating expenses		20,325			15,507			16,295
Extensions, discoveries and improved recovery, net of future production and development costs		6,152			4,485			3,537
Change in estimated future development costs		(5,668	)		(2,747	)		(1,281	)
Revisions of quantity estimates		(3,518	)		(626	)		3,624
Development costs incurred during the period		5,797			3,101			2,483
Accretion of discount		4,014			2,843			1,833
Net change in income taxes		(4,776	)		(4,663	)		(9,528	)
Purchases and sales of reserves in place, net		3,220			1,871			325
Changes in production rates and other		(773	)		908			(1,479	)
Net change		9,530			8,981			8,274
End of year	$	42,267		$	32,737		$	23,756

Average Sales Prices

The following table sets forth, for each of the three years in the period ended December 31, 2011, Occidental’s approximate average sales prices for continuing operations.

			United States		Latin America		(a)	Middle East/ North Africa		Total
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
2009
Oil	–	Average sales price ($/bbl.)	$	56.74	$	55.89		$	58.75	$	57.31
NGLs	–	Average sales price ($/bbl.)	$	37.26	$	―		$	21.88	$	34.27
Gas	–	Average sales price ($/mcf.)	$	3.46	$	5.70		$	1.00	$	2.83

(a)

Excludes average sales prices from Argentine operations sold in February 2011 and classified as discontinued operations and for 2010 and 2009 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, 2011, Occidental’s net productive and dry–exploratory and development wells completed.

			United States		Latin America		(a)	Middle East/ North Africa		Total
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
2009
Oil	–	Exploratory		5.5		―			0.7		6.2
		Development		224.3		61.7			105.3		391.3
Gas	–	Exploratory		―		―			―		―
		Development		14.5		―			2.0		16.5
Dry	–	Exploratory		13.7		―			2.9		16.6
		Development		1.8		0.7			0.7		3.2

(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 and 2009 includes the noncontrolling interest in a Colombian subsidiary.

Productive Oil and Gas Wells

The following table sets forth, as of December 31, 2011, Occidental’s productive oil and gas wells (both producing and capable of production).

Wells at December 31, 2011 (a)			United States			Latin America			Middle East/ North Africa			Total
Oil	–	Gross (b)	31,538	(1,426	)	1,277	(―	)	2,201	(570	)	35,016	(1,996	)
		Net (c)	21,052	(1,101	)	633	(―	)	1,196	(274	)	22,881	(1,375	)
Gas	–	Gross (b)	6,933	(1,388	)	29	(―	)	120	(1	)	7,082	(1,389	)
		Net (c)	5,470	(1,012	)	27	(―	)	62	(1	)	5,559	(1,013	)

(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, 2011, Occidental’s participation in exploratory and development wells being drilled.

Wells at December 31, 2011			United States	Latin America	Middle East/ North Africa	Total
Exploratory and development wells
	–	Gross	280	7	37	324
	–	Net	180	4	19	203

At December 31, 2011, Occidental was participating in 190 pressure-maintenance projects, mostly waterfloods, in the United States, 8 in Latin America and 26 in the Middle East/North Africa.

Oil and Gas Acreage

The following table sets forth, as of December 31, 2011, Occidental’s holdings of developed and undeveloped oil and gas acreage.

Thousands of acres at December 31, 2011			United States	(a)	Latin America	Middle East/ North Africa	Total
Developed (b)
	–	Gross (c)	7,873		120	1,214	9,207
	–	Net (d)	4,646		83	551	5,280
Undeveloped (e)
	–	Gross (c)	5,817		485	18,418	24,720
	–	Net (d)	2,748		364	16,453	19,565

(a)	Includes approximately 1.7 million acres in California, the vast 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. The terms and conditions under which Occidental maintains exploration or production rights to the acreage are property-specific, contractually defined and vary significantly from property to property. 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.

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

Production per Day	2011	2010	2009
United States
Oil (MBBL)
California	80	76	76
Permian	134	136	141
Midcontinent and Other	16	7	6
TOTAL	230	219	223
NGLs (MBBL)
California	15	16	17
Permian	38	29	27
Midcontinent and Other	16	7	4
TOTAL	69	52	48
Natural gas (MMCF)
California	260	280	250
Permian	157	199	199
Midcontinent and Other	365	198	186
TOTAL	782	677	635
Latin America (a)
Oil (MBBL) ― Colombia (b)	29	37	45
Natural gas (MMCF) ― Bolivia	15	16	16
Middle East/North Africa
Oil (MBBL)
Bahrain	4	3	―
Dolphin	9	11	15
Iraq	7	3	―
Libya	4	12	10
Oman	67	62	50
Qatar	73	76	79
Yemen	27	31	34
TOTAL	191	198	188
NGLs (MBBL)
Dolphin	10	13	11
Libya	―	1	1
TOTAL	10	14	12
Natural gas (MMCF)
Bahrain	173	169	10
Dolphin	199	236	257
Oman	54	48	49
TOTAL	426	453	316

Total Production (MBOE) (a,c)	733	711	677
(See footnotes following the Sales Volumes per Day table)

Sales Volumes per Day	2011	2010	2009
United States
Oil (MBBL)	230	219	223
NGLs (MBBL)	69	52	48
Natural gas (MMCF)	782	677	635
Latin America (a)
Oil (MBBL) ― Colombia (b)	29	36	45
Natural gas (MMCF) ― Bolivia	15	16	16
Middle East/North Africa
Oil (MBBL)
Bahrain	4	3	―
Dolphin	9	12	14
Iraq	3	―	―
Libya	4	12	12
Oman	69	61	50
Qatar	73	76	79
Yemen	27	30	35
TOTAL	189	194	190
NGLs (MBBL)
Dolphin	10	12	11
Libya	―	1	―
TOTAL	10	13	11
Natural gas (MMCF)	426	453	316

Total Sales Volumes (MBOE) (a,c)	731	705	678

(a)	For all periods presented, excludes volumes from the Argentine operations sold in February 2011 and classified as discontinued operations.
(b)	Includes production volumes per day of 5 mbbl and 6 mbbl for the years ended December 31, 2010 and 2009, respectively, related to the noncontrolling interest in a Colombian subsidiary. Includes sales volumes per day of 4 mbbl and 6 mbbl for the years ended December 31, 2010 and 2009, respectively, 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.

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

			Additions
	Balance at Beginning of Period		Charged to Costs and Expenses			Charged to Other Accounts			Deductions		(a)	Balance at End of Period
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)
2009
Allowance for doubtful accounts	$	34	$	4		$	―		$	(8	)	$	30

Environmental	$	439	$	26		$	4		$	(66	)	$	403
Litigation, tax and other reserves		288		3			(6	)		(59	)		226

	$	727	$	29		$	(2	)	$	(125	)	$	629	(b)

Note: The amounts presented represent continuing operations.

(a)	Primarily represents payments.
(b)	Of these amounts, $100 million, $102 million and $112 million in 2011, 2010 and 2009, respectively, are classified as current.

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, 2011.

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 2011 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.

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," "Security Ownership – Section 16(a) Beneficial Ownership Reporting Compliance," "Board of Directors and its Committees – Board Committees – Audit Committee," and "General Information – Nominations for Directors for Term Expiring in 2014" in Occidental's definitive proxy statement filed in connection with its May 4, 2012, Annual Meeting of Stockholders (2012 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 2012 Proxy Statement.

Item 12

Security Ownership of Certain Beneficial Owners and Management

This item incorporates by reference the information with respect to security ownership appearing under the caption "Security Ownership – Certain Beneficial Owners and Management" in the 2012 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 "Board of Directors and its Committees – Independence", and " – Related Party Transactions" in the 2012 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 2012 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:

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

2.1*	Agreement and Plan of Merger among Occidental Petroleum Corporation, Occidental Transaction 1, LLC and Vintage Petroleum, Inc., dated as of October 13, 2005. (Disclosure schedules to this agreement have been omitted pursuant to Item 601(b)(2) of Regulation S-K) (filed as Exhibit 2.1 to the Current Report on Form 8-K of Occidental dated October 13, 2005 (filed October 17, 2005), File No. 1-9210).
3.(i)*	Restated Certificate of Incorporation of Occidental, dated November 12, 1999 (filed as Exhibit 3.(i) to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 1999, File No. 1-9210).
3.(i)(a)*	Certificate of Change of Location of Registered Office and of Registered Agent, dated July 6, 2001 (filed as Exhibit 3.1(i) to the Registration Statement on Form S-3 of Occidental, File No. 333-82246).
3.(i)(b)*	Certificate of Amendment of Restated Certificate of Incorporation of Occidental Petroleum Corporation, dated May 5, 2006 (filed as Exhibit 3.(i)(b) to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2006, File No.1-9210).
3.(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).
10.4*	Form of Indemnification Agreement between Occidental and each of its directors and certain executive officers (filed as Exhibit B to the Proxy Statement of Occidental for its May 21, 1987, Annual Meeting of Stockholders, File No. 1-9210).
10.5*	Occidental Petroleum Corporation Split Dollar Life Insurance Program and Related Documents (filed as Exhibit 10.2 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended September 30, 1994, File No. 1-9210).

____________________________

* Incorporated herein by reference

10.6*	Split Dollar Life Insurance Agreement, dated January 24, 2002, by and between Occidental and Donald P. de Brier (filed as Exhibit 10.1 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended March 31, 2002, File No. 1-9210).
10.7*	Occidental Petroleum Insured Medical Plan, as amended and restated effective April 29, 1994, amending and restating the Occidental Petroleum Corporation Executive Medical Plan (as amended and restated effective April 1, 1993) (filed as Exhibit 10 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ending March 31, 1994, File No. 1-9210).
10.8*	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).
10.9*	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).
10.10*	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).
10.11*	Occidental Petroleum Corporation 1996 Restricted Stock Plan for Non-Employee Directors, amended October 11, 2007 (filed as Exhibit 10.1 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended September 30, 2007, File No. 1-9210).
10.12*	Form of Restricted Stock Option Assignment under Occidental Petroleum Corporation 1996 Restricted Stock Plan for Non-Employee Directors (filed as Exhibit 99.2 to the Registration Statement on Form S-8 of Occidental, File No. 333-02901).
10.13*	Form of Restricted Stock Agreement under Occidental Petroleum Corporation 1996 Restricted Stock Plan for Non-Employee Directors (filed as Exhibit 10.3 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended March 31, 2003, File No. 1-9210).
10.14*	Amendment to Form of Restricted Stock Agreement under Occidental Petroleum Corporation 1996 Restricted Stock Plan for Non-Employee Directors (filed as Exhibit 10.2 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended September 30, 2007, File No. 1-9210).
10.15*	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).
10.16*	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).
10.17*	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).
10.18	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).
10.19	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).
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 (filed as Exhibit 10.1 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended September 30, 2001, File No. 1-9210).
10.22*	Form of Nonqualified Stock Option Agreement under Occidental Petroleum Corporation 2001 Incentive Compensation Plan (filed as Exhibit 10.2 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended September 30, 2001, File No. 1-9210).
10.23*	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).
10.24*	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).
10.25*	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).

____________________________

* Incorporated herein by reference

10.26*	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).
10.27*	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).
10.28*	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).
10.29*	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).
10.30*	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).
10.31*	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).
10.32*	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).
10.33*	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).
10.34*	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).
10.35*	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).
10.36*	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).
10.37*	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).
10.38*	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).
10.39*	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).
10.40*	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).
10.41*	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).
10.42*	Terms and Conditions of Performance-Based Stock Award under Occidental Petroleum Corporation 2005 Long-Term Incentive Plan (January 2007 version – Corporate) (filed as Exhibit 10.68 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2006, File No. 1-9210).
10.43*	Terms and Conditions of Performance-Based Stock Award under Occidental Petroleum Corporation 2005 Long-Term Incentive Plan (January 2007 version – Oil and Gas) (filed as Exhibit 10.69 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2006, File No. 1-9210).
10.44*	Terms and Conditions of Performance-Based Stock Award under Occidental Petroleum Corporation 2005 Long-Term Incentive Plan (January 2007 version – Chemicals) (filed as Exhibit 10.70 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2006, File No. 1-9210).
10.45*	Amendment of the Terms and Conditions of 2007 Performance-Based Stock Awards filed as Exhibit 10.48 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2010, 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 18, 2007 (date of earliest event reported), File No. 1-9210).
10.47*	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).

____________________________

* Incorporated herein by reference

10.48*	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).
10.49*	Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Return on Equity Incentive Award (Cash-based, Cash-settled Award) (filed as Exhibit 10.1 to the Current Report On Form 8-K of Occidental dated July 16, 2008 (date of earliest event reported), File No. 1-9210).
10.50*	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).
10.51*	Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Long-Term Incentive Award Agreement (Equity-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, 2008, File No. 1-9210).
10.52*	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).
10.53*	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).
10.54*	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).
10.55*	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).
10.56*	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).
10.57*	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).
10.58*	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).
10.59*	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).
10.60*	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).
10.61*	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).
10.62*	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).
10.63*	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).
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 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).
10.65*	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).
10.66*	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).

____________________________

* Incorporated herein by reference

10.67*	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).
10.68*	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).
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, 2011.
21	List of subsidiaries of Occidental at December 31, 2011.
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, 2011.
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

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 23, 2012	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
Stephen I. Chazen	President,	February 23, 2012
	Chief Executive Officer and Director

/s/ James M. Lienert
James M. Lienert	Executive Vice President and	February 23, 2012
	Chief Financial Officer

/s/ Roy Pineci
Roy Pineci	Vice President, Controller and	February 23, 2012
	Principal Accounting Officer

/s/ Spencer Abraham
Spencer Abraham	Director	February 23, 2012


/s/ Howard I. Atkins
Howard I. Atkins	Director	February 23, 2012


/s/ Edward P. Djerejian
Edward P. Djerejian	Director	February 23, 2012


/s/ John E. Feick
John E. Feick	Director	February 23, 2012


/s/ Margaret M. Foran
Margaret M. Foran	Director	February 23, 2012


/s/ Carlos M. Gutierrez
Carlos M. Gutierrez	Director	February 23, 2012

	Title	Date

Dr. Ray R. Irani	Executive Chairman	February 23, 2012
	of the Board of Directors

/s/Avedick B. Poladian
Avedick B. Poladian	Director	February 23, 2012


/s/ Rodolfo Segovia
Rodolfo Segovia	Director	February 23, 2012


/s/ Aziz D. Syriani
Aziz D. Syriani	Director	February 23, 2012


/s/ Rosemary Tomich
Rosemary Tomich	Director	February 23, 2012


/s/ Walter L. Weisman
Walter L. Weisman	Director	February 23, 2012

This report was printed on recycled paper.

EXHIBITS

10.18	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).

10.19	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).

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, 2011.

21	List of subsidiaries of Occidental at December 31, 2011.

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, 2011.

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.