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, 2012 For the transition period from to

Commission File Number 1-9210

Occidental Petroleum Corporation

(Exact name of registrant as specified in its charter)

State or other jurisdiction of incorporation or organization Delaware

I.R.S. Employer Identification No. 95-4035997

Address of principal executive offices 10889 Wilshire Blvd., Los Angeles, CA

Zip Code 90024

Registrant's telephone number, including area code (310) 208-8800

Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class Name of Each Exchange on Which Registered

9 1/4% Senior Debentures due 2019 New York Stock Exchange

Common Stock New York Stock Exchange

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

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 $68.1 billion, computed by

reference to the closing price on the New York Stock Exchange composite tape of $85.77 per share of Common Stock on June 30, 2012. Shares of

Common Stock held by each executive officer and director have been excluded from this computation in that such persons may be deemed to be

affiliates. This determination of potential affiliate status is not a conclusive determination for other purposes.

At January 31, 2013, there were 805,515,153 shares of Common Stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s definitive Proxy Statement, relating to its May 3, 2013 Annual Meeting of Stockholders, are incorporated by reference

into Part III.
TABLE OF CONTENTS

 Page

Part I

Items 1 and 2 Business and Properties......................................................................................................................................................... 3

General.............................................................................................................................................................................. 3

Oil and Gas Operations..................................................................................................................................................... 3

Chemical Operations......................................................................................................................................................... 4

Midstream, Marketing and Other Operations .................................................................................................................... 5

Capital Expenditures......................................................................................................................................................... 5

Employees......................................................................................................................................................................... 5

Environmental Regulation................................................................................................................................................. 5

Available Information......................................................................................................................................................... 5

Item 1A Risk Factors............................................................................................................................................................................ 6

Item 1B Unresolved Staff Comments................................................................................................................................................... 7

Item 3 Legal Proceedings.................................................................................................................................................................. 7

Item 4 Mine Safety Disclosures........................................................................................................................................................ 7

Executive Officers................................................................................................................................................................... 8

Part II

Item 5 Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities ............... 8

Item 6 Selected Financial Data.......................................................................................................................................................... 11

Item 7 and 7A Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) ..................................... 11

Strategy............................................................................................................................................................................. 12

Oil and Gas Segment........................................................................................................................................................ 13

Chemical Segment............................................................................................................................................................ 19

Midstream, Marketing and Other Segment ........................................................................................................................ 20

Segment Results of Operations......................................................................................................................................... 21

Significant Items Affecting Earnings.................................................................................................................................. 24

Taxes................................................................................................................................................................................. 24

Consolidated Results of Operations .................................................................................................................................. 24

Consolidated Analysis of Financial Position...................................................................................................................... 25

Liquidity and Capital Resources........................................................................................................................................ 26

Off-Balance-Sheet Arrangements...................................................................................................................................... 28

Contractual Obligations..................................................................................................................................................... 28

Lawsuits, Claims and Contingencies................................................................................................................................. 29

Environmental Liabilities and Expenditures ....................................................................................................................... 29

Foreign Investments.......................................................................................................................................................... 30

Critical Accounting Policies and Estimates........................................................................................................................ 30

Significant Accounting and Disclosure Changes ............................................................................................................... 34

Derivative Activities and Market Risk................................................................................................................................. 34

Safe Harbor Discussion Regarding Outlook and Other Forward-Looking Data ................................................................ 36

Item 8 Financial Statements and Supplementary Data ...................................................................................................................... 37

Management's Annual Assessment of and Report on Internal Control Over Financial Reporting ..................................... 37

Report of Independent Registered Public Accounting Firm on Consolidated Financial Statements ................................. 38

Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting ....................... 39

Consolidated Balance Sheets........................................................................................................................................... 40

Consolidated Statements of Income.................................................................................................................................. 42

Consolidated Statements of Comprehensive Income ....................................................................................................... 43

Consolidated Statements of Stockholders' Equity ............................................................................................................. 43

Consolidated Statements of Cash Flows ........................................................................................................................... 44

Notes to Consolidated Financial Statements ..................................................................................................................... 45

Quarterly Financial Data (Unaudited)................................................................................................................................ 73

Supplemental Oil and Gas Information (Unaudited).......................................................................................................... 75

Financial Statement Schedule:

Schedule II – Valuation and Qualifying Accounts.............................................................................................................. 87

Item 9 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure .................................................. 8 8

Item 9A Controls and Procedures........................................................................................................................................................ 8 8

Disclosure Controls and Procedures ................................................................................................................................. 8 8

Item 9B Other Information.................................................................................................................................................................... 8 8

Part III
Part III

Item 10 Directors, Executive Officers and Corporate Governance ...................................................................................................... 8 8

Item 11 Executive Compensation........................................................................................................................................................ 8 8

Item 12 Security Ownership of Certain Beneficial Owners and Management ..................................................................................... 89

Item 13 Certain Relationships and Related Transactions and Director Independence ........................................................................ 89

Item 14 Principal Accountant Fees and Services................................................................................................................................. 89

Part IV

Item 15 Exhibits and Financial Statement Schedules .......................................................................................................................... 89
Part I

ITEMS 1 AND 2 BUSINESS AND PROPERTIES

In this report, "Occidental" means Occidental Petroleum

Corporation, a Delaware corporation (OPC), or OPC and one or more

entities in which it owns a controlling interest

(subsidiaries). Occidental conducts its operations through various

subsidiaries and affiliates. Occidental’s executive offices are located

at 10889 Wilshire Boulevard, Los Angeles, California 90024; telephone

(310) 208-8800.

GENERAL

Occidental’s principal businesses consist of three segments. The

oil and gas segment explores for, develops and produces oil and

condensate, natural gas liquids (NGLs) and natural gas. The

chemical segment (OxyChem) mainly manufactures and markets

basic chemicals and vinyls. The midstream, marketing and other

segment (midstream and marketing) gathers, processes, transports,

stores, purchases and markets oil, condensate, NGLs, natural gas,

carbon dioxide (CO2) and power. It also trades around its assets,

including transportation and storage capacity, and trades oil, NGLs,

gas and other commodities. The segment also invests in entities that

conduct similar activities.

For information regarding Occidental's current developments,

segments and geographic areas, see the information in the

"Management’s Discussion and Analysis of Financial Condition and

Results of Operations" (MD&A) section of this report and Note 16 to the

Consolidated Financial Statements.

OIL AND GAS OPERATIONS

General

Occidental’s domestic oil and gas operations are located mainly in

California, Colorado, Kansas, New Mexico, North Dakota, Oklahoma,

Texas and West Virginia. International operations are located in

Bahrain, Bolivia, Colombia, Iraq, Libya, Oman, Qatar, the United

Arab Emirates (UAE) and Yemen. 

Proved Reserves and Sales Volumes

The table below shows Occidental’s total oil, NGLs and natural

gas proved reserves and sales volumes in 2012, 2011 and 2010. See

"MD&A — Oil and Gas Segment," and the information under the

caption "Supplemental Oil and Gas Information" for certain details

regarding Occidental’s proved reserves, the reserves estimation

process, sales and production volumes, production costs and other

reserves-related data.

Comparative Oil and Gas Proved Reserves and Sales Volumes

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

millions.

2012 2011 2010

Proved Reserves Oil NGLs Gas BOE (a) Oil NGLs Gas BOE (a) Oil NGLs Gas BOE (a)

United States 1,567 216 2,889 2,265 1,526 225 3,365 2,313 1,460 237 3,034 2,203

International (b,c) 469 116 2,679 1,031 482 55 1,958 863 552 61 2,104 964

Total 2,036 332 5,568 3,296 (d) 2,008 280 5,323 3,176 (d) 2,012 298 5,138 3,167 (d)

Sales Volumes

United States 93 27 300 170 84 25 285 156 80 19 247 140

International (b,c) 78 3 170 110 80 4 162 111 83 5 172 117

Total 171 30 470 280 164 29 447 267 163 24 419 257

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

75-78.

(a) Natural gas volumes have been converted to BOE based on energy content of six thousand cubic feet (Mcf) of gas to one barrel of oil. Barrels of oil equivalence does not necessarily result in

price equivalence. The price of natural gas on a barrel of oil equivalent basis is currently substantially lower than the corresponding price for oil and has been similarly lower over the

recent past. For example, in 2012, the average prices of West Texas Intermediate (WTI) oil and New York Mercantile Exchange (NYMEX) natural gas were $94.21 per barrel and $2.81

per Mcf, respectively, resulting in an oil to gas ratio of over 30.

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

(c) Reserves exclude the former noncontrolling interest in a Colombian subsidiary because, on December 31, 2010, Occidental restructured its Colombian operations to take a direct

working interest in the related assets. The 2010 sales volumes include the noncontrolling interest in the Colombian subsidiary, while the 2012 and 2011 sales volumes exclude such

amounts.

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

2012, 1.0 billion BOE in 2011 and 1.1 billion BOE in 2010.

3
Competition

As a producer of oil and condensate, NGLs and natural gas,

Occidental competes with numerous other domestic and foreign

private and government producers. Oil, NGLs and natural gas are

commodities that are sensitive to prevailing global and, in certain

cases local, current and anticipated market conditions. They are sold

at current market prices or on a forward basis to refiners and other

market participants. Occidental’s competitive strategy relies on

increasing production through developing conventional and

unconventional mature and underdeveloped fields, enhanced oil

recovery (EOR) projects and strategic acquisitions. Occidental also

competes to develop and produce its worldwide oil and gas reserves

cost-effectively and obtain qualified labor and services.

CHEMICAL OPERATIONS

General

OxyChem owns and operates manufacturing plants at 22

domestic sites in Alabama, Georgia, Illinois, Kansas, Louisiana,

Michigan, New Jersey, New York, Ohio, Pennsylvania and Texas

and at two international sites in Canada and Chile. It also has an

interest in a Brazilian joint venture.

Competition

OxyChem competes with numerous other domestic and foreign

chemical producers. For every product it manufactures and markets,

OxyChem’s market position was first or second in the United States

and first, second or third in the world in 2012. OxyChem’s competitive

strategy is to be a low-cost producer of its products in order to compete

on price.

OxyChem produces the following products:

Principal Products Major Uses Annual Capacity

Basic Chemicals

Chlorine Raw material for ethylene dichloride (EDC), water treatment and

pharmaceuticals

4.0 million tons (a)

Caustic soda Pulp, paper and aluminum production 4.2 million tons (a)

Chlorinated organics Refrigerants, silicones and pharmaceuticals 0.9 billion pounds

Potassium chemicals Fertilizers, batteries, soaps, detergents and specialty glass 0.4 million tons

EDC Raw material for vinyl chloride monomer (VCM) 2.4 billion pounds (a)

Chlorinated isocyanurates Swimming pool sanitation and disinfecting products 131 million pounds

Sodium silicates Catalysts, soaps, detergents and paint pigments 0.6 million tons

Calcium chloride Ice melting, dust control, road stabilization and oil field services 0.7 million tons

Vinyls

VCM Precursor for polyvinyl chloride (PVC) 6.2 billion pounds

PVC Piping, building materials, and automotive and medical products 3.7 billion pounds

Other Chemicals

Resorcinol Tire manufacture, wood adhesives and flame retardant synergist 50 million pounds

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

4
MIDSTREAM AND MARKETING OPERATIONS

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

Location Description Capacity

Gas Plants

California, Texas, New Mexico and

Colorado

Occidental- and third-party-operated natural gas

gathering, compression and processing systems,

and CO2 processing

3.1 billion cubic feet per day

Pipelines

Texas, New Mexico and Oklahoma Common carrier oil pipeline and storage system 365,000 barrels of oil per day

5.8 million barrels of oil storage

2,700 miles of pipeline

Texas, New Mexico and Colorado CO2 fields and pipeline systems transporting

CO2 to oil and gas producing locations

2.4 billion cubic feet per day

Dolphin Pipeline - Qatar and United

Arab Emirates

Equity investment in a natural gas pipeline 3.2 billion cubic feet of natural gas per day (a)

Western and Southern United

States and Canada

Equity investment in entity involved in pipeline

transportation, storage, terminalling and

marketing of oil, gas and related petroleum

products

18,800 miles of pipeline and gathering systems

(b)

Storage for 135 million barrels of oil and other

petroleum products and 93 billion cubic feet

of natural gas(b)

Marketing and Trading

Texas, Connecticut, United

Kingdom, Singapore and other

Trades around its assets, including transportation

and storage capacity, and purchases, markets

and trades oil, NGLs, gas, power and other

commodities

Not applicable

Power Generation

California, Texas and Louisiana Occidental-operated power and steam generation

facilities

1,800 megawatts per hour and 1.6 million

pounds of steam per hour

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

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

CAPITAL EXPENDITURES

For information on capital expenditures, see the information

under the heading "Liquidity and Capital Resources” in the MD&A

section of this report.

EMPLOYEES

Occidental employed approximately 12,300 people at

December 31, 2012, 8,700 of whom were located in the United States.

Occidental employed approximately 8,000 people in the oil and gas

and midstream and marketing segments and 3,000 people in the

chemical segment. An additional 1,300 people were employed in

administrative and headquarters functions. Approximately 800 U.S.-

based employees and 700 foreign-based employees are represented

by labor unions.

Occidental has a long-standing strict policy to provide fair and

equal employment opportunities to all applicants and employees.

ENVIRONMENTAL REGULATION

For environmental regulation information, including associated

costs, see the information under the heading "Environmental

Liabilities and Expenditures" in the MD&A section of this report and

"Risk Factors."

AVAILABLE INFORMATION

Occidental makes the following information available free of

charge on its website at www.oxy.com:

Ø Forms 10-K, 10-Q, 8-K and amendments to these forms as soon as

reasonably practicable after they are electronically filed with, or

furnished to, the Securities and Exchange Commission (SEC);

Ø Other SEC filings, including Forms 3, 4 and 5; and

Ø Corporate governance information, including its corporate

governance guidelines, board-committee charters and Code of

Business Conduct. (See Part III, Item 10, of this report for further

information.)

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

report.

5
ITEM 1A RISK FACTORS

Volatile global and local commodity pricing strongly affects

Occidental’s results of operations.

Occidental’s financial results correlate closely to the prices it

obtains for its products, particularly oil and, to a lesser extent, natural

gas and its chemical products.

Changes in consumption patterns, global and local economic

conditions, inventory levels, production disruptions, the actions of

OPEC, currency exchange rates, worldwide drilling and exploration

activities, technological developments, weather, geophysical and

technical limitations, transportation bottlenecks and other matters

affect the supply and demand dynamics of oil and gas, which, along

with the effect of changes in market perceptions, contribute to price

unpredictability and volatility.

Demand and, consequently, the price obtained for Occidental’s

chemical products correlate strongly to the health of the United States

and global economies, as well as chemical industry expansion and

contraction cycles. Occidental also depends on feedstocks and energy

to produce chemicals, which are commodities subject to significant

price fluctuations.

Occidental’s oil and gas business operates in highly

competitive environments, which affect, among other things, its

results of operations and its ability to grow production and

replace reserves.

Results of operations, reserve replacement and growth in oil and

gas production depend, in part, on Occidental’s ability to profitably

acquire, develop or find additional reserves. Occidental has many

competitors (including national oil companies), some of which: (i) are

larger and better funded, (ii) may be willing to accept greater risks or

(iii) have special competencies. Competition for reserves may make it

more difficult to find attractive investment opportunities or require

delay of reserve replacement efforts. During periods of low product

prices, any cash conservation efforts may delay production growth and

reserve replacement efforts.

Occidental may experience delays, cost overruns, losses or

unrealized expectations in development efforts and exploration

activities.

Occidental bears the risks of development delays and cost

overruns due to approval delays for drilling and other permits,

equipment failures, construction delays, escalating costs or

competition for services, materials, supplies or labor, property or border

disputes, disappointing reservoir performance and other associated

risks that may affect its ability to profitably grow production, replace

reserves and achieve its targeted returns.

Exploration is inherently risky. Exploration is subject to delays,

misinterpretation of geologic or engineering data, unexpected geologic

conditions or finding reserves of disappointing quality or quantity,

which may result in significant losses.

Governmental actions and political instability may affect

Occidental’s results of operations.

Occidental’s businesses are subject to the decisions of many

governments and political interests. As a result, Occidental faces risks

of:

Ø new or amended laws and regulations, or interpretations of such

laws and regulations, including those related to drilling,

manufacturing or production processes (including hydraulic

fracturing), labor and employment, taxes, royalty rates, permitted

production rates, entitlements, import, export and use of

equipment, use of land, water and other natural resources,

safety, security and environmental protection, all of which may

increase Occidental’s costs or reduce the demand for its products;

and

Ø refusal of, or delay in, the extension or grant of exploration,

development or production contracts.

Occidental may experience adverse consequences, such as risk

of loss or production limitations, because certain of its foreign

operations are located in countries occasionally affected by political

instability, armed conflict, terrorism, insurgency, civil unrest, security

problems, labor unrest, OPEC production restrictions, equipment

import restrictions and sanctions. Exposure to such risks may increase

if a greater percentage of Occidental’s future oil and gas production

comes from foreign sources.

Occidental faces risks associated with its acquisitions and

divestitures.

Occidental’s acquisition and divestiture activities carry risks that

it may: (i) not fully realize anticipated benefits due to less-thanexpected reserves or production or changed circumstances, such as

the deterioration of natural gas prices over the last few years; (ii) bear

unexpected integration costs or experience other integration

difficulties; (iii) experience share price declines based on the market’s

evaluation of the activity; or (iv) assume or retain liabilities that are

greater than anticipated.

Occidental’s oil and gas reserves are based on professional

judgments and may be subject to revision.

Reported oil and gas reserves are an estimate based on

engineers' periodic review of reservoir characteristics and

recoverability, including production decline rates, operating

performance and economic feasibility at the prevailing commodity

prices as well as capital and operating costs. If Occidental were

required to make significant negative reserve revisions, its results of

operations and stock price could be adversely affected.

6
Concerns about climate change may affect Occidental’s

operations.

The U.S. federal government and the state of California have

adopted, and other jurisdictions are considering, legislation,

regulations or policies that seek to control or reduce the production,

use or emissions of “greenhouse gases” (GHG), to control or reduce

the production or consumption of fossil fuels, and to increase the use

of renewable or alternative energy sources. For example, California’s

cap-and-trade program currently applies to Occidental's operations in

the state. The U.S. Environmental Protection Agency has begun to

regulate certain GHG emissions from both stationary and mobile

sources. The uncertain outcome and timing of existing and proposed

international, national and state measures make it difficult to predict

their business impact. However, Occidental could face risks of project

execution, higher costs and taxes and lower demand for and

restrictions on the use of its products as a result of ongoing GHG

reduction efforts.

Occidental’s businesses may experience catastrophic

events.

The occurrence of events, such as earthquakes, hurricanes,

floods, well blowouts, fires, explosions, chemical releases, industrial

accidents, physical attacks and other events that cause operations to

cease or be curtailed, may negatively affect Occidental’s businesses

and the communities in which it operates. Third-party insurance may

not provide adequate coverage or Occidental may be self-insured with

respect to the related losses.

Cyber attacks could significantly affect Occidental.

Cyber attacks on businesses have escalated in recent years.

Occidental relies on electronic systems and networks to control and

manage its oil and gas, chemicals, trading and pipeline operations

and has multiple layers of security to mitigate risks of cyber attack. If,

however, Occidental were to experience an attack and its security

measures failed, the potential consequences to its businesses and the

communities in which it operates could be significant. In 2009 and

2010, Occidental experienced a cyber attack on its email system,

which had no effect on its operations, financial systems or reputation.

Other risk factors.

Additional discussion of risks and uncertainties related to price

and demand, litigation, environmental matters, oil and gas reserves

estimation processes, foreign operations, impairments, derivatives,

market risks and internal controls appears under the

headings: "MD&A — Oil & Gas Segment — Proved Reserves" and

"— Industry Outlook," "— Chemical Segment — Industry Outlook,"

"— Midstream, Marketing and Other Segment — Industry Outlook,"

"— Consolidated Results of Operations," "— Lawsuits, Claims and

Other Contingencies," "— Environmental Liabilities and

Expenditures," "— Foreign Investments," "— Critical Accounting

Policies and Estimates," "— Derivative Activities and Market Risk,"

and "Management's Annual Assessment of and Report on Internal

Control Over Financial Reporting."

The risks described in this report are not the only risks facing

Occidental and other risks, including risks deemed immaterial, may

have material adverse effects.

ITEM 1B UNRESOLVED STAFF COMMENTS

Occidental has no unresolved SEC staff comments that have

been outstanding more than 180 days at December 31, 2012.

ITEM 3 LEGAL PROCEEDINGS

A subsidiary of OPC reached a settlement in principle in January

2013 with the Louisiana Department of Environmental Quality

regarding penalties associated with certain self-disclosed air emissions

and permit deviations. Under the proposed settlement, the subsidiary

will pay administrative penalties and an additional amount to fund air

quality modeling as a supplemental environmental project.

The New Mexico Environment Department asserted a penalty

claim on April 6, 2012, against an OPC subsidiary for alleged

notification, permitting and emissions violations of the New Mexico Air

Quality Control Act at a facility in Lea County, New Mexico. The

subsidiary is evaluating this claim.

Although the matters described above are reportable events, their

financial impact is expected to be insignificant.

For information regarding other legal proceedings, see the

information under the caption, "Lawsuits, Claims and Other

Contingencies" in the MD&A section of this report and in Note 9 to the

Consolidated Financial Statements.

ITEM 4 MINE SAFETY DISCLOSURES

Not applicable.

7
EXECUTIVE OFFICERS

The current term of employment of each executive officer of Occidental will expire at the May 3, 2013, organizational meeting of the Board of

Directors or when a successor is selected. The following table sets forth the executive officers of Occidental:

Name

Age at

February 26, 2013 Positions with Occidental and Subsidiaries and Employment History

Stephen I. Chazen 66 Chief Executive Officer since 2011 and President since 2007; 2010-2011, Chief Operating Officer; 1999-2010,

Chief Financial Officer; Director since 2010.

Dr. Ray R. Irani 78 Executive Chairman since 2011; 1990-2011, Chairman and Chief Executive Officer; Director since 1984.

Cynthia L. Walker 36 Executive Vice President and Chief Financial Officer since 2012; Goldman, Sachs & Co.: 2010-2012,

Managing Director; 2005-2010, Vice President.

Donald P. de Brier 72 Corporate Executive Vice President and Corporate Secretary since 2012; 1993-2012, Executive Vice

President, General Counsel and Secretary.

William E. Albrecht 61 Vice President since 2008; Occidental Oil and Gas Corporation (OOGC): President — Oxy Oil & Gas,

Americas since 2011; OOGC: President — Oxy Oil & Gas, USA 2008-2011; 2007-2008, Vice President,

California Operations.

Edward A. "Sandy" Lowe 61 Vice President since 2008; OOGC: President — Oxy Oil & Gas, International Production since 2009; 2008-

2009, Executive Vice President — Oxy Oil & Gas, International Production and Engineering; 2008,

Executive Vice President — Oxy Oil & Gas, Major Projects.

Willie C.W. Chiang 52 Executive Vice President, Operations since 2012; ConocoPhillips: 2011-2012, Senior Vice President,

Refining, Marketing, Transportation and Commercial; 2008-2011, Senior Vice President, Refining,

Marketing and Transportation.

James M. Lienert 60 Executive Vice President — Business Support since 2012; 2010-2012, Executive Vice President and Chief

Financial Officer; 2006-2010, Executive Vice President — Finance and Planning.

John C. Ale 58 Vice President and General Counsel since 2012; Skadden, Arps, Slate, Meagher & Flom LLP: 2002-2012,

Partner.

Roy Pineci 50 Vice President, Controller and Principal Accounting Officer since 2008; 2007-2008, Senior Vice President,

Finance — Oil and Gas.

B. Chuck Anderson 53 Vice President since 2012; President of Occidental Chemical Corporation since 2006.

Part II

ITEM 5 MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER

PURCHASES OF EQUITY SECURITIES

TRADING PRICE RANGE AND DIVIDENDS

This section incorporates by reference the quarterly financial data appearing under the caption "Quarterly Financial Data (Unaudited)" after

the Notes to the Consolidated Financial Statements, and the information appearing under the caption "Liquidity and Capital Resources" in the

MD&A section of this report. Occidental’s common stock was held by approximately 32,200 stockholders of record at December 31, 2012, and by

approximately 494,000 additional stockholders whose shares were held for them in street name or nominee accounts. The common stock is listed

and traded on the New York Stock Exchange. The quarterly financial data, which are included in this report after the Notes to the Consolidated

Financial Statements, set forth the range of trading prices for the common stock as reported on the composite tape of the New York Stock Exchange

and quarterly dividend information.

The quarterly dividends declared on the common stock were $0.54 for each quarter of 2012 ($2.16 for the year). On February 14, 2013, a

quarterly dividend of $0.64 per share was declared on the common stock, payable on April 15, 2013 to stockholders of record on March 8, 2013. The

declaration of future dividends is a business decision made by the Board of Directors from time to time, and will depend on Occidental’s financial

condition and other factors deemed relevant by the Board.

8
SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS

All of Occidental's stock-based compensation plans for its employees and non-employee directors have been approved by the stockholders. The

aggregate number of shares of Occidental common stock authorized for issuance under such plans is approximately 66 million, of which

approximately 15 million had been issued through December 31, 2012. The following is a summary of the securities available for issuance under

such plans:

a) Number of securities to be issued upon exercise

of outstanding options, warrants and rights

b) Weighted-average exercise price of

outstanding options, warrants and rights

c) Number of securities remaining available for

future issuance under equity compensation

plans (excluding securities in column (a))

3,502,857 (1) 31.88 (2) 19,251,258 (3)

(1) Includes shares reserved to be issued pursuant to stock options (Options), stock appreciation rights (SARs) and performance-based awards. Shares for

performance-based awards are included assuming maximum payout, but may be paid out at lesser amounts, or not at all, according to achievement of

performance goals.

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

(3) A plan provision requires each share covered by an award (other than Options and SARs) to be counted as if three shares were issued in determining the

number of shares that otherwise would have been available for future awards. Accordingly, the number of shares available for future awards may be less than

the amount shown depending on the type of award granted. Additionally, under the plan, the amount shown may increase by the number of shares currently

unvested or forfeitable, or three times that number as applicable, that (i) fail to vest, (ii) are forfeited or cancelled, or (iii) correspond to the portion of any stockbased awards settled in cash.

SHARE REPURCHASE ACTIVITIES

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

Period

Total

Number

of Shares

Purchased (a)

Average

Price

Paid

per Share

Total Number of Shares

Purchased as Part of Publicly

Announced

Plans or Programs

Maximum Number of Shares

that May Yet Be Purchased Under

the

Plans or Programs

First Quarter 2012 144,542 $ 104.84 —

Second Quarter 2012 1,760,000 $ 81.19 1,760,000

Third Quarter 2012 583,072 $ 86.58 470,000

October 1-31, 2012 620,000 $ 80.24 620,000

November 1-30, 2012 2,860,000 $ 75.90 2,860,000

December 1-31, 2012 1,520,000 $ 74.92 1,520,000

Fourth Quarter 2012 5,000,000 $ 76.14 5,000,000

Total 2012 7,487,614 $ 78.69 7,230,000 17,255,575 (b)

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

(b) Occidental has had a 95 million share repurchase program authorized since 2008; however, the program does not obligate Occidental to acquire any specific

number of shares and may be discontinued at any time.

9
PERFORMANCE GRAPH

The following graph compares the yearly percentage change in Occidental’s cumulative total return on its common stock with the cumulative

total return of the Standard & Poor's 500 Stock Index (S&P 500) and with that of Occidental’s peer group over the five-year period ended on

December 31, 2012. The graph assumes that $100 was invested at the beginning of the five-year period shown in the graph below in (i)

Occidental common stock, (ii) the stock of the companies in the S&P 500 and (iii) each of the peer group companies' common stock weighted by

their relative market values within the peer group, and that all dividends were reinvested.

Occidental's peer group consists of Anadarko Petroleum Corporation, Apache Corporation, Canadian Natural Resources Limited, Chevron

Corporation, ConocoPhillips, Devon Energy Corporation, EOG Resources Inc., ExxonMobil Corporation, Hess Corporation, Royal Dutch Shell plc,

Total S.A. and Occidental.

12/31/2007 12/31/2008 12/31/2009 12/31/2010 12/31/2011 12/31/2012

$ 100 $ 79 $ 110 $ 135 $ 131 $ 110

100 75 82 93 102 104

100 63 80 92 94 109

The information provided in this Performance Graph shall not be deemed "soliciting material" or "filed" with the Securities and Exchange Commission or subject

to Regulation 14A or 14C under the Exchange Act, other than as provided in Item 201 to Regulation S-K under the Exchange Act, or subject to the liabilities of

Section 18 of the Exchange Act and shall not be deemed incorporated by reference into any filing under the Securities Act of 1933 or the Exchange Act except to

the extent Occidental specifically requests that it be treated as soliciting material or specifically incorporates it by reference.

_______________________

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

10
ITEM 6 SELECTED FINANCIAL DATA

FIVE-YEAR SUMMARY OF SELECTED FINANCIAL DATA

Dollar amounts in millions, except per-share amounts

As of and for the years ended December 31, 2012 2011 2010 2009 2008

RESULTS OF OPERATIONS (a)

Net sales $ 24,172 $ 23,939 $ 19,045 $ 14,814 $ 23,713

Income from continuing operations (b) $ 4,635 $ 6,640 $ 4,569 $ 3,151 $ 7,183

Net income attributable to common stock $ 4,598 $ 6,771 $ 4,530 $ 2,915 $ 6,857

Basic earnings per common share from continuing operations (b) $ 5.72 $ 8.16 $ 5.62 $ 3.88 $ 8.77

Basic earnings per common share (b) $ 5.67 $ 8.32 $ 5.57 $ 3.59 $ 8.37

Diluted earnings per common share (b) $ 5.67 $ 8.32 $ 5.56 $ 3.58 $ 8.34

FINANCIAL POSITION (a)

Total assets $ 64,210 $ 60,044 $ 52,432 $ 44,229 $ 41,537

Long-term debt, net $ 7,023 $ 5,871 $ 5,111 $ 2,557 $ 2,049

Stockholders’ equity $ 40,048 $ 37,620 $ 32,484 $ 29,159 $ 27,325

MARKET CAPITALIZATION (c) $ 61,710 $ 75,992 $ 79,735 $ 66,050 $ 48,607

CASH FLOW

Operating:

Cash provided by operating activities $ 11,312 $ 12,281 $ 9,566 $ 5,946 $ 10,765

Investing:

Capital expenditures $ (10,226) $ (7,518) $ (3,940) $ (3,245) $ (4,126)

Cash used by all other investing activities, net $ (2,429) $ (2,385) (d) $ (5,355) $ (2,221) $ (5,314)

Financing:

Cash dividends paid $ (2,128) (e) $ (1,436) $ (1,159) $ (1,063) $ (940)

Cash provided (used) by all other financing activities, net $ 1,282 $ 261 $ 2,242 $ 30 $ (570)

DIVIDENDS PER COMMON SHARE $ 2.16 $ 1.84 $ 1.47 $ 1.31 $ 1.21

WEIGHTED AVERAGE BASIC SHARES OUTSTANDING (thousands) 809,345 812,075 812,472 811,305 817,635

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

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

operations and other items affecting comparability.

(b) Represent amounts attributable to common stock after deducting noncontrolling interest amounts of $72 million in 2010, $51 million in 2009 and $116 million

in 2008. There were no noncontrolling interests in 2012 and 2011.

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

closing stock price.

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

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

following year.

ITEM 7 AND 7A

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND

RESULTS OF OPERATIONS (MD&A)

In this report, "Occidental" means Occidental Petroleum

Corporation (OPC), or OPC and one or more entities in which it owns

a controlling interest (subsidiaries). Occidental's principal businesses

consist of three segments operated by OPC's subsidiaries and

affiliates. The oil and gas segment explores for, develops and produces

oil and condensate, natural gas liquids (NGLs) and natural gas. The

chemical segment (OxyChem) mainly

manufactures and markets basic chemicals and vinyls. The

midstream, marketing and other segment (midstream and marketing)

gathers, processes, transports, stores, purchases and markets oil,

condensate, NGLs, natural gas, carbon dioxide (CO 2) and power. It

also trades around its assets, including transportation and storage

capacity, and trades oil, NGLs, gas and other commodities. The

segment also invests in entities that conduct similar activities.

11
STRATEGY

General

Occidental aims to maximize total returns to stockholders using the

following strategies:

Ø Grow oil and gas production through development programs

focused on large, long-lived conventional and unconventional oil

and gas assets with long-term growth potential, and acquisitions;

Ø Allocate and deploy capital with a focus on achieving returns well

in excess of Occidental's cost-of-capital;

Ø Provide consistent dividend growth; and

Ø Maintain financial discipline and a strong balance sheet.

In conducting its business, Occidental accepts commodity,

engineering and limited exploration risks. Occidental seeks to limit its

financial and political risks.

Occidental prioritizes the use of its cash flows in the following

order:

Ø Maintenance capital

Ø Dividends

Ø Growth capital

Ø Acquisitions

Ø Share repurchases

Capital is employed to operate all assets in a safe and

environmentally sound manner. Management aims to develop

Occidental's assets in a manner that they would contribute

substantially to earnings and cash flow after invested capital. The

following describes the application of Occidental's overall strategy to

each of its operating segments.

Oil and Gas

Segment Earnings

($ millions)

Occidental prefers to hold large, long-lived "legacy" oil and gas

assets, like those in California and the Permian Basin, that tend to

have enhanced secondary and tertiary recovery opportunities and

economies of scale that lead to cost-effective production. Occidental

also focuses a portion of its drilling activities on unconventional shale

opportunities.

The oil and gas business seeks to increase its oil and gas

production profitably and add new reserves at a pace

ahead of production while minimizing costs incurred for finding and

development of such reserves. The oil and gas business implements

this strategy within the limits of the overall corporate strategy primarily

by:

Ø Deploying capital to fully develop areas where reserves are

known to exist and increase production from mature fields by

applying appropriate technology and advanced reservoirmanagement practices;

Ø Adding reserves through a combination of focused exploration and

development programs conducted in Occidental's core areas,

which are the United States, the Middle East/North Africa and

Latin America; and

Ø Maintaining a disciplined approach to acquisitions and

divestitures with an emphasis on transactions at attractive prices.

Over the past several years, Occidental has strengthened its

asset base within its core areas. Occidental has invested in, and

disposed of, assets with the goal of raising the average performance

and potential of its assets.

In 2012, Occidental paid approximately $2.3 billion for domestic

oil and gas properties in the Permian Basin, the Williston Basin,

California and South Texas.

Management currently believes Occidental's growth will be most

strongly affected by the success of the development plans for its

Permian, California and Oman assets and the Al Hosn gas project in

Abu Dhabi where it continues to deploy significant capital.

Occidental's oil and gas production has grown approximately five

percent annually during the three-year period ended December 31,

2012.

Chemical

Segment Earnings

($ millions)

The primary objective of the chemical business is to generate cash

flow in excess of its normal capital expenditure requirements and

achieve above-cost-of-capital returns. The chemical segment's

(OxyChem) strategy is to be a low-cost producer in order to maximize

its cash flow generation. OxyChem concentrates on the chlorovinyls

chain beginning with chlorine, which is co-produced with caustic

soda, and markets both to third parties. In addition, chlorine, together

with ethylene, is converted through a series of intermediate products

into PVC. OxyChem's focus on chlorovinyls allows it to maximize the

benefits of integration and take advantage of

12
economies of scale. Capital is employed to sustain production capacity

and to focus on projects and developments designed to improve the

competitiveness of segment assets. Acquisitions and plant

development opportunities may be pursued when they are expected

to enhance the existing core chlor-alkali and PVC businesses or take

advantage of other specific opportunities. During 2012, OxyChem

began construction of a chlor-alkali plant in Tennessee, which it

expects to begin operating in the fourth quarter of 2013.

Midstream and Marketing

Segment Earnings

($ millions)

The midstream and marketing segment is managed to generate

returns on capital employed in excess of Occidental's cost of capital. In

order to generate these returns, the segment evaluates opportunities

across the value chain and uses its assets to provide services to other

segments and third parties. In marketing its own and third-party

production, Occidental strives to maximize realized value using its

assets, including transportation and storage capacity. In commodities

trading, Occidental seeks to generate gains using net-long positions.

The segment invests in and operates gas plants, co-generation

facilities, pipeline systems and storage facilities. The segment also

seeks to minimize the costs of gas, power and other commodities used

in Occidental's businesses and to limit credit risk exposure. Capital is

employed to sustain or, where appropriate, increase operational

capacity and to improve the competitiveness of Occidental's assets.

Occidental and Magellan Midstream Partners, L.P. are proceeding

with the construction of the BridgeTex Pipeline which will transport

crude oil between the Permian region and the Gulf Coast refinery

markets and is expected to begin service in mid-2014.

Key Performance Indicators

General

Occidental seeks to meet its strategic goals by continually

measuring its success in its key performance metrics that drive total

stockholder return. In addition to production growth and capital

allocation and deployment discussed above, Occidental believes the

following are its most significant metrics:

Ø Cash margin per barrel;

Ø Free-cash-flow yield;

Ø Dividend growth;

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

Occidental also monitors other segment-specific indicators such as

per-unit profit, production costs and finding and development costs, as

well as health, environmental and safety measures, like the number

of recordable injuries, and others.

Based on the $2.56 per share annual dividend rate announced

in February 2013, Occidental’s dividend rate has increased by 412

percent since 2002. While its stockholders' equity increased by 6

percent for 2012 and 37 percent for the three-year period from 2010

through 2012, Occidental continued to deliver above-cost-of-capital

returns as follows:

Annual 2012 (a)

Three-Year Annual

Average 2010 - 2012 (b)

ROE

14.6%

15.2%

{11.8%}

ROCE 12.6%13.5%

{10.3%}

(a) The top figures for ROE and ROCE for 2012 were calculated by dividing

Occidental's 2012 income after removing the effect of Significant Items

Affecting Earnings described on page 24 (while adding back after-tax interest

expense for the ROCE calculation) by its average equity and capital

employed, respectively, during 2012. We provide this adjusted measure

because we believe it would be useful to investors in evaluating and

comparing Occidental's performance between periods, not as a substitute for

the measure calculated using net income. The bottom figure is the same

calculation but using net income attributable to common stock in the

numerator (while adding back after-tax interest expense for the ROCE

calculation).

(b) The three-year average ROE and ROCE were calculated by dividing

Occidental's average net income attributable to common stock (while adding

back after-tax interest expense for the ROCE calculation) over the three-year

period 2010-2012 by its average equity and capital employed, respectively,

over the same period.

Debt Structure

Occidental issued $1.75 billion of senior unsecured notes in the

second quarter of 2012 for general corporate purposes including

ordinary course working capital increases, acquisitions, stock

repurchases, retirement of debt and other business opportunities. As a

result of Occidental’s commitment to financial discipline, its year-end

2012 total debt-to-capitalization (debt and equity) ratio was 16 percent.

OIL AND GAS SEGMENT

Business Environment

Oil and gas prices are the major variables that drive the

industry’s short- and intermediate-term financial performance. The

following table presents the average daily West Texas Intermediate

(WTI), Brent and New York Mercantile Exchange (NYMEX) prices for

2012 and 2011:

2012 2011

WTI oil ($/barrel) $ 94.21 $ 95.12

Brent oil ($/barrel) $ 111.70 $ 110.90

NYMEX gas ($/Mcf) $ 2.81 $ 4.11

13
The following table presents Occidental's average realized prices

as a percentage of WTI, Brent and NYMEX for 2012 and 2011:

2012 2011

Worldwide oil as a percentage of average WTI 106% 103%

Worldwide oil as a percentage of average Brent 89% 88%

Worldwide NGLs as a percentage of average WTI 48% 58%

Domestic natural gas as a percentage of NYMEX 93% 99%

Average realized oil prices were slightly higher in 2012 than

2011. Approximately 60 percent of Occidental’s oil production tracks

world oil prices, such as Brent, and 40 percent tracks WTI. The

average realized domestic natural gas price in 2012 decreased 35

percent from 2011.

Prices and differentials can vary significantly, even on a shortterm basis, making it impossible to predict realized prices with a

reliable degree of certainty.

Operations

Domestic Interests

Occidental conducts its domestic operations through land leases,

subsurface mineral rights it owns or a combination of both surface

land and subsurface mineral rights it owns. Occidental's domestic oil

and gas leases have a primary term ranging from one to ten years,

which is extended through the end of production once production

commences. Of the total 8.1 million net acres in which Occidental has

interests, approximately 74 percent is leased, 25 percent is owned

subsurface mineral rights and 1 percent is owned land with mineral

rights.

Production-Sharing Contracts (PSC)

Occidental has interests that are operated under PSCs or similar

contracts in Bahrain, Iraq, Libya, Oman, Qatar and Yemen. Under

such contracts, Occidental records a share of production and reserves

to recover certain production costs and an additional share for profit. In

addition, Occidental's share of production and reserves from

operations in Long Beach, California, and certain contracts in

Colombia are subject to contractual arrangements similar to a PSC.

These contracts do not transfer any right of ownership to Occidental

and reserves reported from these arrangements are based on

Occidental’s economic interest as defined in the contracts.

Occidental’s share of production and reserves from these contracts

decreases when product prices rise and increases when prices

decline. Overall, Occidental’s net economic benefit from these

contracts is greater when product prices are higher.

Business Review

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

five years:

Worldwide Production Volumes

(thousands BOE/day)

Notes:

• Includes average production volumes per day of 5 thousand barrels

(mbbl), 6 mbbl and 6 mbbl for 2010, 2009 and 2008, respectively, related

to the noncontrolling interest in a Colombian subsidiary.

• Excludes volumes from the Argentine operations sold in February 2011

and classified as discontinued operations.

United States Assets

United States

1. Permian

2. California

3. Midcontinent and Other interests

Permian

Occidental's Permian production is diversified across a large

number of producing areas in the Permian Basin. The Permian Basin

extends throughout southwest Texas and southeast New Mexico and

is one of the largest and most active oil basins in the United States,

accounting for approximately 15 percent of the total United States oil

production.

Occidental is the largest producer of oil in the Permian Basin with

an approximate 16 percent net share of the total oil production.

Occidental also produces and processes natural gas and NGLs in the

Permian Basin. Occidental continued to increase its Permian

interests in 2012 through various acquisitions, a significant portion of

which related to its non-CO2 operations which comprised

approximately 1.5 million net acres at the end of 2012.

14
Approximately 60 percent of Occidental’s Permian oil production is

from fields that actively employ CO2 flood technology, an enhanced oil

recovery (EOR) technique. This technique involves injecting CO2

into oil reservoirs where it causes the oil to flow more freely into

producing wells. These CO2 flood operations make Occidental a world

leader in the application of this technology. 

Occidental’s interests in Permian offer significant additional

development and exploitation potential. During 2012, Occidental

drilled approximately 550 wells on its operated properties and

participated in additional wells drilled on third-party-operated

properties. Occidental also focused on improving the performance of

existing wells.

Occidental's Permian non-CO2 operations are among its fastest

growing assets. Since beginning significant delineation and

development efforts in 2010, production from these operations has

increased by more than 25 percent. The development program

continued to increase in 2012 accounting for more than 300 of the

wells drilled in Permian.

Occidental's share of production in Permian was approximately

207,000 BOE per day in 2012.

California

Occidental's California operations include interests in the Elk

Hills area, the Wilmington and other fields in the Los Angeles Basin

and the Ventura, San Joaquin and Sacramento Basins. Occidental

has properties in more than 125 fields in California, an increase from

2011 resulting from various property acquisitions in 2012.

Occidental's interests in the Elk Hills area include the Elk Hills oil

and gas field in the southern portion of California’s San Joaquin

Valley, which it operates with an approximate 78-percent interest,

along with other adjacent properties. The Elk Hills Field is the largest

producer of gas and NGLs in California. During 2012, Occidental

continued to invest in the Elk Hills area, performing infill drilling,

field extensions and recompletions identified by advanced reservoir

characterization techniques, resulting in approximately 320 new

wells being drilled.

Occidental began operating a new gas processing plant in Elk

Hills in 2012 with capacity to handle 200 million cubic feet per day.

Occidental's share of production in California was approximately

148,000 BOE per day in 2012.

Occidental holds approximately 2.1 million net acres in

California, the large majority of which are net fee mineral interests.

As a result, Occidental has a substantial inventory of properties

available for future development and exploitation in conventional

areas, as well as unconventional prospects, such as shale. Occidental

drilled approximately 760 wells in California during 2012.

Midcontinent and Other

The Midcontinent and Other properties include interests in the

Hugoton Field, the Piceance Basin, the Williston Basin, the

Marcellus Shale in the Appalachian Basin, the Eagle Ford Shale and

other areas in South Texas. These properties are located in Kansas,

Oklahoma, Colorado, North Dakota, West Virginia and Texas.

Occidental holds over 2.3 million net acres in the Midcontinent

region, which includes 1.4 million net acres in a large concentration

of gas reserves and production and royalty interests in the Hugoton

area and approximately 0.4 million net acres in the Piceance area.

Occidental also holds approximately 160,000 net acres in South

Texas, including 4,000 net acres in the Eagle Ford Shale, which was

acquired in 2012. In addition, Occidental holds approximately

341,000 net acres of oil producing and prospective unconventional

properties in the Williston Basin's Bakken and Three Forks

formations. In addition, Occidental holds approximately 235,000 net

acres in West Virginia.

In Midcontinent and Other, Occidental drilled approximately 260

wells and produced approximately 110,000 BOE per day in 2012.

Other Developments

Management conducted a review of Occidental’s portfolio of oil

and gas assets in the fourth quarter of 2012 and concluded that,

given the current and anticipated natural gas pricing environment

and the effect of reserve revisions from price changes and well

performance, certain of its domestic natural gas producing properties

had become impaired. Occidental also concluded that certain projects

had become uneconomical and that it would not pursue them. As a

result, Occidental recorded pre-tax impairment charges of $1.7 billion,

almost all of which were for certain assets in Midcontinent, over 90

percent of which were related to natural gas properties that were

acquired more than four years ago on average when gas prices were

more than $6 per Mcf.

Middle East/North Africa Assets

Middle East/North Africa

1. Bahrain

2. Iraq

3. Libya

4. Oman

5. Qatar

6. United Arab Emirates

7. Yemen

15
Bahrain

In 2009, Occidental and other consortium members began

operating the Bahrain Field under a 20-year development and

production sharing agreement (DPSA). Occidental has a 48-percent

working interest in the joint venture. Since handover of operations,

the consortium has increased gross gas production capacity more than

60 percent from an initial level of 1.5 billion cubic feet per day to over

2.4 billion cubic feet per day and increased gross oil production from

26,000 barrels per day to 42,000 barrels per day. The consortium

plans to continue growing gross gas production capacity to over 2.7

billion cubic feet per day and gross oil production to over 75,000

barrels per day. Occidental's share of production from Bahrain during

2012 was approximately 232 million cubic feet (MMcf) per day of gas

and 4,000 barrels of oil per day.

Iraq

In 2010, Occidental and other consortium members signed a 20-

year contract with the South Oil Company of Iraq to develop the

Zubair Field. Occidental has a 23.44-percent interest in this contract,

which entitles Occidental to receive oil for cost recovery and a

remuneration fee, as a result of having achieved an initial gross

production threshold in 2010. The consortium plans to increase

production to a contractually targeted production level of 1.2 million

BOE per day by 2016 and maintain this level of production for seven

years. Occidental's share of production from Iraq was approximately

11,000 BOE per day in 2012.

Libya

Occidental participates with subsidiaries of the Libyan National

Oil Company in Sirte Basin producing operations. These agreements

continue through 2032. The 2012 production volume was

approximately 12,000 BOE per day.

Oman

In Oman, Occidental is the operator of Block 9 and Block 27, with

a 65-percent working interest in each block; Block 53, with a 45-

percent working interest; and Block 62, with a 48-percent working

interest.

A 30-year PSC for the Mukhaizna Field (Block 53) was signed

with the Government of Oman in 2005, pursuant to which Occidental

assumed operation of the field. By the end of 2012, Occidental had

drilled almost 1,800 new wells and continued implementation of a

major steamflood project. In 2012, the average gross daily production

was 120,000 BOE per day, which was over 15 times higher than the

production rate in September 2005.

The term for Block 9 continues through 2015, with a 10-year

extension right for certain areas. The term for Block 27 expires in

2035.

In 2008, Occidental was awarded a 20-year contract for Block 62,

subject to declaration of commerciality, where it is pursuing

development and exploration opportunities targeting gas and

condensate resources.

Occidental's share of production from Oman was approximately

76,000 BOE per day in 2012.

Qatar

In Qatar, Occidental is the operator at Idd El Shargi North Dome

(ISND) and Idd El Shargi South Dome (ISSD), with a 100-percent

working interest in each, and Al Rayyan (Block 12), with a 92.5-

percent working interest. The terms for ISND, ISSD and Block 12

expire in 2019, 2022 and 2017, respectively.

In 2011, Occidental received approval from the Government of

Qatar for the fourth phase of field development of the ISND Field,

focusing on continued development of mature reservoirs while further

delineating and developing less mature reservoirs. Occidental also

received approval for field development plans for ISSD and Al

Rayyan, which include additional drilling through 2013.

Occidental's Dolphin investment comprises two separate economic

interests through which Occidental owns: (i) a 24.5-percent undivided

interest in the upstream operations under a DPSA with the

Government of Qatar to develop and produce natural gas and NGLs in

Qatar’s North Field through mid-2032, with a provision to request a

five-year extension; and (ii) a 24.5-percent interest in the stock of

Dolphin Energy Limited (Dolphin Energy), which is discussed further

in "Midstream, Marketing and Other Segment – Pipeline

Transportation."

Occidental's share of production from Qatar was approximately

114,000 BOE per day in 2012.

United Arab Emirates

In the first quarter of 2011, Occidental acquired a 40-percent

participating interest in the Al Hosn gas project, joining with the Abu

Dhabi National Oil Company (ADNOC) in a 30-year joint venture

agreement. The project is anticipated to produce over 500 MMcf per

day of natural gas, of which Occidental’s net share would be over 200

MMcf per day. In addition, the project is expected to produce over

50,000 barrels per day of NGLs and condensates, of which

Occidental’s net share would be over 20,000 barrels per day.

Occidental’s 2012 capital expenditures for this project were

approximately $1.2 billion. A substantial portion of the total

expenditures to date has been incurred in connection with plants and

facilities and is included in the midstream and marketing segment. As

the development progresses, higher portions of the capital

expenditures will be spent to drill wells, which will be reflected in the

oil and gas segment. Occidental believes that its share of total 2013

capital for the project will be approximately $1.1 billion.

Occidental conducts a majority of its Middle East business

development activities through its office in Abu Dhabi, which also

provides various support functions for Occidental’s Middle East/North

Africa oil and gas operations.

Yemen

In Yemen, Occidental owns interests in: Block 10 East Shabwa

Field, which extends through 2015 with a 40.4-percent interest that

includes an 11.8-percent interest held in an unconsolidated entity,

and Block S-1 An Nagyah Field, which is an Occidental-operated

block with a 75-percent working interest that extends into 2023.

16
Occidental's share of production from the Yemen properties was

approximately 14,000 BOE per day in 2012.

Latin America Assets

Latin America

1. Bolivia

2. Colombia

Bolivia

Occidental holds working interests in the Tarija, Chuquisaca and

Santa Cruz regions of Bolivia, which produce gas.

Colombia

Occidental has a working interest in the La Cira-Infantas area

and has operations within the Llanos Norte Basin. Occidental's

interests range from 39 to 61 percent and certain interests expire

between 2023 and 2030, while others extend through the economic

limit of the areas. Occidental's share of production was approximately

29,000 BOE per day in 2012.

Proved Reserves

Proved oil, NGL and gas reserves were estimated using the

unweighted arithmetic average of the first-day-of-the-month price for

each month within the year, unless prices were defined by

contractual arrangements. Oil, NGL and gas prices used for this

purpose were based on posted benchmark prices and adjusted for

price differentials including gravity, quality and transportation costs.

For the 2012, 2011 and 2010 disclosures, the calculated average West

Texas Intermediate oil prices were $94.71, $96.19 and $79.43 per

barrel, respectively. The calculated average Henry Hub gas prices for

2012, 2011 and 2010 disclosures were $2.79, $4.04 and $4.39 per

MMBtu, respectively.

Occidental had proved reserves at year-end 2012 of 3,296 million

BOE, as compared with the year-end 2011 amount of 3,176 million

BOE. Proved reserves at year-end 2012 and 2011 consisted of,

respectively, 62 percent and 63 percent oil, 10 percent and 9 percent

NGLs and 28 percent and 28 percent natural gas. Proved developed

reserves represented approximately 73 percent and 76 percent,

respectively, of Occidental’s total proved reserves at year-end 2012

and 2011.

Occidental does not have any reserves from non-traditional

sources. For further information regarding Occidental's proved

reserves, see "Supplemental Oil and Gas Information" following the

"Financial Statements."

Proved Reserve Additions

Occidental's total proved reserve additions from all sources were

400 million BOE in 2012. The total additions were as follows:

In millions of BOE

Improved recovery 257

Extensions and discoveries 232

Purchases 94

Revisions of previous estimates (183)

Total additions 400

Occidental's ability to add reserves, other than through

purchases, depends on the success of improved recovery, extension

and discovery projects, each of which depends on reservoir

characteristics, technology improvements and oil and natural gas

prices, as well as capital and operating costs. Many of these factors

are outside of management’s control, and will affect whether these

historical sources of proved reserve additions continue at similar

levels.

Improved Recovery

In 2012, Occidental added proved reserves of 257 million BOE

from improved recovery through its EOR and infill drilling activities.

Generally, the improved recovery additions in 2012 were associated

with the continued development of properties in California, Permian,

South Texas and Oman. These properties comprise both conventional

projects, which are characterized by the deployment of EOR

development methods, largely employing application of waterflood,

steamflood or CO2 injection, and unconventional projects. These

types of conventional EOR development methods are often applied

through existing wells, though additional drilling may be required to

fully optimize the development configuration. Waterflooding is the

technique of injecting water into the formation to displace the oil to the

offsetting oil production wells. Steamflooding is the technique of

injecting steam into the formation to lower oil viscosity so that it flows

more freely into producing wells. This process is applied in areas

where the oil is too viscous to be effectively moved with water. CO2

flooding involves injecting CO2 into oil reservoirs where it causes the

oil to flow more freely into producing wells. Many of Occidental's

projects, including unconventional projects, rely on improving

permeability to increase flow in the wells. In addition, some improved

recovery comes from drilling infill wells that allow recovery of reserves

that would not be recoverable from existing wells.

Extensions and Discoveries

Occidental also obtained reserve additions from extensions and

discoveries, which are dependent on successful exploration and

exploitation programs. In 2012, extensions and discoveries added 232

million BOE, a substantial majority of which is attributable to the

17
recognition of initial proved undeveloped reserves from the Al Hosn

gas project.

Purchases and Divestitures of Proved Reserves

Occidental continues to add reserves through acquisitions when

properties are available at prices it deems reasonable. As market

conditions change, the available supply of properties may increase or

decrease accordingly. In 2012, Occidental added 94 million BOE

through purchases of proved reserves largely consisting of several

domestic acquisitions in the Permian Basin, California, Williston

Basin and South Texas.

Revisions of Previous Estimates

Revisions can include upward or downward changes to previous

proved reserve estimates for existing fields due to the evaluation or

interpretation of geologic, production decline or operating performance

data. In addition, product price changes affect proved reserves

recorded by Occidental. For example, higher prices may increase the

economically recoverable reserves, particularly for domestic

properties, because the extra margin extends the expected life of the

operations. Offsetting this effect, higher prices decrease Occidental's

share of proved reserves under PSCs because less oil is required to

recover costs. Conversely, when prices drop, Occidental's share of

proved reserves increases for PSCs and economically recoverable

reserves may drop for other operations. In 2012, revisions of previous

estimates provided a net 183 million BOE reduction to proved

reserves.

In 2012, revisions related to price for the company as a whole

were negative. A substantial majority of such revisions related to

Occidental's domestic gas reserves and resulted from lower domestic

gas prices. These lower prices and the resulting changes in

Occidental's plans for drilling on gas properties constituted a majority

of its total revisions. To the extent gas prices recover in the future, a

portion of these reserves will be reinstated. If natural gas prices

decrease further for an extended period, domestic gas reserves could

experience additional negative price revisions.

Other negative revisions were mainly due to reservoir

performances in Elk Hills and Midcontinent and Other. The revisions

involved several properties where wells experienced higher-thanexpected decline rates. Sizable portions of these revisions were

transferred from the proved category to probable, possible and

contingent categories.

Reserve estimation rules require that estimated ultimate

recoveries be much more likely to increase or remain constant than to

decrease as changes are made due to increased availability of

technical data. As a result, apart from the effect of product prices, it is

generally more likely that future proved reserve revisions will be

positive in aggregate over time rather than negative.

Proved Undeveloped Reserves

In 2012, Occidental had proved undeveloped reserve additions of

443 million BOE from improved recovery, extensions and discoveries

and purchases. Of the total additions, 171 million BOE represented

additions from

improved recovery, primarily in California, Permian, South Texas and

Oman. Occidental added 46 million BOE through purchases of proved

undeveloped reserves domestically in the Permian and Williston

Basins and California. Additionally, the proved undeveloped reserves

increased due to extensions and discoveries mainly from the Al Hosn

gas project. These proved undeveloped reserve additions were offset

by transfers of 229 million BOE to the proved developed category as a

result of the 2012 development programs and by revisions of 98 million

BOE, which is included in total revisions discussed above. These

revisions were in the same locations as those discussed above and

factors that caused them were substantially the same as those that

caused the changes to total proved reserves. Occidental incurred

approximately $3.4 billion in 2012 to convert proved undeveloped

reserves to proved developed reserves. Permian, Bahrain, California,

Oman and Williston accounted for approximately 86 percent of the

reserves transfers from proved undeveloped to proved developed in

2012. Costs to develop proved undeveloped reserves have increased

over time and may continue to increase.

Reserves Evaluation and Review Process

Occidental’s estimates of proved reserves and associated future

net cash flows as of December 31, 2012, were made by Occidental’s

technical personnel and are the responsibility of management. The

estimation of proved reserves is based on the requirement of

reasonable certainty of economic producibility and funding

commitments by Occidental to develop the reserves. This process

involves reservoir engineers, geoscientists, planning engineers and

financial analysts. As part of the proved reserves estimation process,

all reserves volumes are estimated by a forecast of production rates,

operating costs and capital expenditures. Price differentials between

benchmark prices (the unweighted arithmetic average of the first-dayof-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.

18
The current Senior Vice President, Reserves for Oxy Oil and Gas

is responsible for overseeing the preparation of reserve estimates, in

compliance with SEC rules and regulations, including the internal

audit and review of Occidental's oil and gas reserves data. The Senior

Vice President has over 30 years of experience in the upstream sector

of the exploration and production business, and has held various

assignments in North America, Asia and Europe. He is a three-time

past Chair of the Society of Petroleum Engineers Oil and Gas

Reserves Committee. He is an American Association of Petroleum

Geologists (AAPG) Certified Petroleum Geologist and currently serves

on the AAPG Committee on Resource Evaluation. He is a member of

the Society of Petroleum Evaluation Engineers, the Colorado School of

Mines Potential Gas Committee and the UNECE Expert Group on

Resource Classification. He is also an active member of the Joint

Committee on Reserves Evaluator Training (JCORET). The Senior

Vice President has Bachelor of Science and Master of Science

degrees in geology from Emory University in Atlanta.

Occidental has a Corporate Reserves Review Committee

(Reserves Committee), consisting of senior corporate officers, to review

and approve Occidental's oil and gas reserves. The Reserves

Committee reports to the Audit Committee of Occidental's Board of

Directors during the year. Since 2003, Occidental has retained Ryder

Scott Company, L.P. (Ryder Scott), independent petroleum

engineering consultants, to review its annual oil and gas reserve

estimation processes.

In 2012, Ryder Scott conducted a process review of Occidental’s

methods and analytical procedures utilized by Occidental’s

engineering and geological staff for estimating the proved reserves

volumes, preparing the economic evaluations and determining the

reserves classifications as of December 31, 2012, in accordance with

the U.S. Securities and Exchange Commission (SEC) regulatory

standards. Ryder Scott reviewed the specific application of such

methods and procedures for selected oil and gas properties considered

to be a valid representation of Occidental’s 2012 year-end total proved

reserves portfolio. In 2012, Ryder Scott reviewed approximately 20

percent of Occidental’s proved oil and gas reserves. Since being

engaged in 2003, Ryder Scott has reviewed the specific application of

Occidental’s reserve estimation methods and procedures for

approximately 70 percent of Occidental’s existing proved oil and gas

reserves. Management retains Ryder Scott to provide objective thirdparty input on its methods and procedures and to gather industry

information applicable to Occidental’s reserve estimation and reporting

process. Ryder Scott has not been engaged to render an opinion as to

the reasonableness of reserves quantities reported by Occidental.

Occidental has filed Ryder Scott's independent report as an exhibit to

this Form 10-K.

Based on its reviews, including the data, technical processes and

interpretations presented by Occidental, Ryder Scott has concluded

that the overall procedures and methodologies Occidental utilized in

estimating the proved reserves volumes for the reviewed properties

are appropriate for the purpose thereof and comply with current SEC

regulations.

Industry Outlook

The petroleum industry is highly competitive and subject to

significant volatility due to numerous current and anticipated market

conditions. The WTI and Brent oil price indexes have fluctuated

throughout 2012, settling at $91.82 per barrel and $111.11 per barrel

as of December 31, 2012.

Oil prices will continue to be affected by (i) global supply and

demand, which are generally a function of global economic

conditions, inventory levels, production disruptions, technological

advances, regional market conditions and the actions of OPEC, other

significant producers and governments, (ii) currency exchange rates

and (iii) the effect of changes in these variables on market

perceptions. These factors make it impossible to predict the future

direction of oil prices reliably. Occidental continues to adjust to

economic conditions by adjusting capital expenditures in line with

current economic conditions with the goal of keeping returns well

above its cost of capital.

NGL prices are related to the supply and demand for the

components of products making up these liquids. Some of them more

typically correlate to the price of oil while others are affected by

natural gas prices as well as the demand for certain chemical products

for which they are used as feedstock. In addition, infrastructure

constraints magnify the pricing volatility from region to region. The

volatility in all of these markets makes it impossible to predict NGL

prices reliably.

Domestic natural gas prices and local differentials are strongly

affected by local supply and demand fundamentals, as well as

government regulations and availability of transportation capacity from

producing areas. These and other factors can cause prices to be

volatile, making it impossible to predict domestic gas prices reliably.

International gas prices are generally fixed under long-term contracts.

CHEMICAL SEGMENT

Business Environment

Chemical segment earnings decreased in 2012, notably because

margins were lower across most product lines as price and volume

declines more than offset lower feedstock costs. While the overall

United States economy experienced modest growth, the lower

margins were primarily due to weaker economic conditions in Europe

and Asia, and increased competitive activity from these regions.

Business Review

Basic Chemicals

During 2012, United States manufacturing sectors experienced

weak growth much of the year, resulting in soft domestic demand and

pricing for basic chemical products. Industry chlorine production

decreased by approximately 2 percent, compared to 2011. Chlorine

prices decreased throughout the year due to lower chlorine demand

caused by the slowdown of the Chinese economy and the European

debt crisis. Exports of downstream chlorine derivatives into the vinyls

chain remained competitive in offshore markets as a result of the

North America feedstock cost advantages, which are driven mostly by

natural gas prices. Pricing for liquid caustic soda began 2012

generally

19
soft because the markets anticipated increasing supply due to the

improving United States economy. Prices improved in the last two

quarters of 2012 as a result of favorable global caustic soda supply and

demand balances, resulting in prices finishing slightly above the

prior year level. Businesses such as calcium chloride and potassium

hydroxide were also negatively impacted by a mild winter and

drought conditions in the United States.

During 2012, OxyChem began construction of a 182,500-ton-peryear membrane chlor-alkali plant in Tennessee, which it expects to

begin operating in the fourth quarter of 2013.

Vinyls

Demand in the domestic housing and commercial construction

markets increased, resulting in a year-over-year domestic vinyl

demand increase of approximately 8 percent in 2012. The higher

domestic demand combined with a modest growth in exports

contributed to an approximately 4-percent industry-wide increase in

domestic operating rates compared to 2011. Industry margins also

increased in 2012 due to a combination of higher PVC selling prices

and lower ethylene costs. Ethylene costs, which are a significant

component of PVC feedstock costs, increased outside North America in

2012 due to the greater dependence on naphtha-based production

versus ethane in the United States. North American-produced

ethylene continues to be cost-competitive versus prices in Europe and

Asia, giving North American vinyl products an advantage in global

markets. Industry-wide North American exports of PVC accounted for

greater than 35 percent of the total sales of North American producers.

Industry Outlook

Industry performance will depend on the health of the global

economy, specifically in the housing, construction, automotive and

durable goods markets. Margins also depend on market supply and

demand balances and feedstock and energy prices.

Basic Chemicals

Occidental expects that if the United States housing, automotive

and durable goods markets continue to improve, domestic demand for

basic chemical products should be higher in 2013. With improving

demand, chlorine and caustic soda margins would be expected to

remain at least at 2012 levels. The continued competitiveness of

downstream chlorine derivatives in global markets is contingent on

United States feedstock costs, primarily natural gas and ethylene,

remaining favorable compared to other global markets.

Vinyls

North American demand and operating rates for vinyls should

improve further in 2013 if growth of housing starts and commercial

construction continues. Occidental expects export demand to remain

firm and industry margins to improve as operating rates increase.

MIDSTREAM AND MARKETING SEGMENT

Business Environment

Midstream and marketing segment earnings are affected by the

performance of its marketing and trading businesses and its

processing, transportation and power generation assets. The

marketing and trading businesses aggregate and market Occidental's

and third-party volumes, trade oil, gas and other commodities and

engage in storage activities. Earnings related to processing and

transportation are affected by the volumes that are processed at, and

transported through, the segment's plants and pipelines, as well as

the margins obtained on related services.

The midstream and marketing segment earnings in 2012 were

comparable to 2011 and reflected improved marketing and trading

performance offset by lower gas processing margins.

Business Review

Oil and Gas Marketing and Trading

The marketing and trading group markets substantially all of

Occidental’s oil, NGLs and gas production, trades around its assets,

including transportation and storage capacity, and engages in

commodities trading. Occidental’s third-party marketing and trading

activities focus on purchasing oil, NGLs and gas for resale from parties

whose oil and gas supply is located near its transportation and storage

assets. These purchases allow Occidental to aggregate volumes to

improve marketing earnings. In addition, Occidental’s Phibro trading

unit's strategy is to profit from market price changes. Marketing and

trading performance is affected primarily by commodity price changes

and margins in oil and gas transportation and storage programs. The

marketing and trading group's earnings increased in 2012.

Gas Processing Plants and CO2 Fields and Facilities

Occidental processes its and third-party domestic wet gas to

extract NGLs and other gas byproducts, including CO 2, and delivers

dry gas to pipelines. Margins primarily result from the difference

between inlet costs of wet gas and market prices for NGLs.

Occidental’s 2012 earnings from these operations decreased compared

to 2011, which reflected lower NGL prices.

Occidental, together with ADNOC, is constructing a gas plant and

facilities as part of the Al Hosn gas project in Abu Dhabi, which is

expected to be operational in 2014.

Pipeline Transportation

Margin and cash flow from pipeline transportation operations

mainly reflect volumes shipped. Dolphin Energy owns and operates a

230-mile-long, 48-inch-diameter natural gas pipeline (Dolphin

Pipeline), which transports dry natural gas from Qatar to the UAE and

Oman. The Dolphin Pipeline contributes significantly to Occidental's

pipeline transportation results through Occidental's 24.5-percent

interest in Dolphin Energy. The Dolphin Pipeline has capacity to

transport up to 3.2 Bcf of natural gas per day and currently transports

approximately 2.3 Bcf per day. Demand for natural gas in the UAE

and Oman has grown and Dolphin Energy’s customers have

requested additional

20
gas supplies. To help fulfill this growing demand, Dolphin Energy will

continue to pursue an agreement to secure an additional supply of

gas from Qatar.

Occidental owns an oil common carrier pipeline and storage

system with approximately 2,700 miles of pipelines from southeast

New Mexico across the Permian Basin of southwest Texas to Cushing,

Oklahoma. The system has a current throughput capacity of about

365,000 barrels per day, 5.8 million barrels of active storage capability

and 85 truck unloading facilities at various points along the system,

which allow for additional volumes to be delivered into the pipeline.

Occidental owns 35 percent of the general partner of Plains AllAmerican Pipeline, L.P. (Plains Pipeline), a publicly traded oil and

gas pipeline transportation, storage, terminalling and marketing

entity in the western and southern United States and Canada. The

Plains Pipeline contributed over 20 percent of the segment's earnings

for 2012.

Occidental and Magellan Midstream Partners, L.P. are

proceeding with the construction of the BridgeTex Pipeline, which is

expected to begin service in mid-2014. The approximately 450-milelong pipeline will be capable of transporting approximately 300,000

barrels per day of crude oil between the Permian region (Colorado

City, TX) and the Gulf Coast refinery markets. The BridgeTex Pipeline

project also includes construction of approximately 2.6 million barrels

of oil storage in aggregate.

Occidental's 2012 pipeline transportation earnings improved due

to higher volumes and pricing, and higher income from Plains

Pipeline, partially offset by lower earnings from the Dolphin Pipeline.

Power Generation Facilities

Earnings from power and steam generation facilities are derived

from sales to affiliates and third parties and are generally not

material. 

Industry Outlook

The pipeline transportation and power generation businesses are

expected to remain relatively stable. The gas processing plant

operations could have volatile results depending mostly on NGL

prices, which cannot be predicted. Generally, higher NGL prices

result in higher profitability. Based on its framework of controls and

risk management systems, however, Occidental does not expect the

volatility of these operations to be significant to the company as a

whole. Although the marketing and the trading businesses

individually can cause volatility, the operations together tend to offset

each other, significantly reducing the overall volatility of the

midstream and marketing segment.

SEGMENT RESULTS OF OPERATIONS

Segment earnings exclude income taxes, interest income,

interest expense, environmental remediation expenses, unallocated

corporate expenses and discontinued operations, but include gains

and losses from dispositions of segment assets and income from the

segments' equity investments. Seasonality is not a primary driver of

changes in Occidental's consolidated quarterly earnings during the

year.

The following table sets forth the sales and earnings of each

operating segment and corporate items:

In millions,

except per share amounts

For the years ended December

31, 2012 2011 2010

NET SALES (a)

Oil and Gas $ 18,906 $ 18,419 $ 14,276

Chemical 4,580 4,815 4,016

Midstream and Marketing 1,399 1,447 1,471

Eliminations (a) (713) (742) (718)

$ 24,172 $ 23,939 $ 19,045

EARNINGS

Oil and Gas (b,c) $ 7,095 $ 10,241 $ 7,151

Chemical 720 861 438

Midstream and Marketing 439 448 472

8,254 11,550 8,061

Unallocated corporate items

Interest expense, net (d) (117) (284) (93)

Income taxes (e) (3,118) (4,201) (2,995)

Other (384) (425) (404)

Income from continuing

operations (b) 4,635 6,640 4,569

Discontinued operations, net

(f) (37) 131 (39)

Net Income (b) $ 4,598 $ 6,771 $ 4,530

Basic Earnings per Common

Share $ 5.67 $ 8.32 $ 5.57

(a) Intersegment sales eliminate upon consolidation and are generally made at

prices approximating those that the selling entity would be able to obtain in

third-party transactions.

(b) Oil and gas segment earnings, income from continuing operations and net

income represent amounts attributable to common stock after deducting a

noncontrolling interest amount of $72 million for 2010.

(c) The 2012 amount includes pre-tax charges of $1.7 billion for the impairment

of domestic gas assets and related items. The 2011 amount includes pre-tax

charges of $35 million related to exploration write-offs in Libya and $29

million related to a Colombian net worth tax, and a pre-tax gain for the sale

of an interest in a Colombian pipeline of $22 million. The 2010 amount

includes a $275 million pre-tax charge for asset impairments, predominately

of gas properties in the Rocky Mountain region. 

(d) The 2011 amount includes a pre-tax charge of $163 million related to the

premium on debt extinguishment.

(e) The 2011 amount includes a net $21 million charge for out-of-period state

income taxes. The 2010 amount includes an $80 million benefit related to

foreign tax credit carryforwards. 

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

Argentine operations. 

21
Oil and Gas

Dollars in millions, except as indicated

2012 2011 2010

Segment Sales $ 18,906 $ 18,419 $ 14,276

Segment Earnings $ 7,095 (a) $ 10,241 $ 7,151

(a) Includes pre-tax charges of $1.7 billion for the impairment of domestic gas

assets and related items.

The following tables set forth the production and sales volumes of

oil, NGLs and natural gas per day for each of the three years in the

period ended December 31, 2012. The differences between the

production and sales volumes per day are generally due to the timing

of shipments at Occidental’s international locations where product is

loaded onto tankers.

Production per Day 2012 2011 2010

United States

Oil (MBBL)

California 88 80 76

Permian 142 134 136

Midcontinent and Other 25 16 7

Total 255 230 219

NGLs (MBBL)

California 17 15 16

Permian 39 38 29

Midcontinent and Other 17 16 7

Total 73 69 52

Natural gas (MMCF)

California 256 260 280

Permian 155 157 199

Midcontinent and Other 410 365 198

Total 821 782 677

Latin America (a)

Oil (MBBL) – Colombia (b) 29 29 37

Natural gas (MMCF) – Bolivia 13 15 16

Middle East/North Africa

Oil (MBBL)

Bahrain 4 4 3

Dolphin 8 9 11

Oman 67 67 62

Qatar 71 73 76

Other 36 38 46

Total 186 191 198

NGLs (MBBL)

Dolphin 8 10 13

Other 1 — 1

Total 9 10 14

Natural gas (MMCF)

Bahrain 232 173 169

Dolphin 163 199 236

Oman 57 54 48

Total 452 426 453

Total Production (MBOE) (a,c) 766 733 711

(See footnotes following the Average Sales Price table)

Sales Volumes per Day 2012 2011 2010

United States

Oil (MBBL) 255 230 219

NGLs (MBBL) 73 69 52

Natural gas (MMCF) 819 782 677

Latin America (a)

Oil (MBBL) – Colombia (b) 28 29 36

Natural gas (MMCF) – Bolivia 13 15 16

Middle East/North Africa

Oil (MBBL)

Bahrain 4 4 3

Dolphin 8 9 12

Oman 66 69 61

Qatar 71 73 76

Other 36 34 42

Total 185 189 194

NGLs (MBBL)

Dolphin 8 10 12

Other 1 — 1

Total 9 10 13

Natural gas (MMCF) 452 426 453

Total Sales Volumes (MBOE) (a,c) 764 731 705

(See footnotes following the Average Sales Prices table)

2012 2011 2010

Average Sales Prices

Oil Prices ($ per bbl)

United States $ 93.72 $ 92.80 $ 73.79

Latin America (a) $ 98.35 $ 97.16 $ 75.29

Middle East/North Africa $ 108.76 $ 104.34 $ 76.67

Total worldwide (a) $ 99.87 $ 97.92 $ 75.16

NGL Prices ($ per bbl)

United States $ 46.07 $ 59.10 $ 48.86

Middle East/North Africa $ 37.74 $ 32.09 $ 30.64

Total worldwide $ 45.18 $ 55.53 $ 45.08

Gas Prices ($ per Mcf)

United States $ 2.62 $ 4.06 $ 4.53

Latin America (a) $ 11.85 $ 10.11 $ 7.73

Total worldwide (a) $ 2.06 $ 3.01 $ 3.11

Expensed Exploration $ 345 $ 258 $ 262

Capital Expenditures

Development $ 7,554 $ 5,686 $ 2,955

Exploration $ 622 $ 421 $ 194

Other $ 44 $ 38 $ 17

(a) For all periods presented, excludes volumes and amounts from the

Argentine operations sold in February 2011 and classified as discontinued

operations.

(b) Includes production and sales volumes per day of 5 mbbl and 4 mbbl,

respectively, for the year ended December 31, 2010, related to the

noncontrolling interest in a Colombian subsidiary. 

(c) Natural gas volumes have been converted to BOE based on energy content of

six Mcf of gas to one barrel of oil.

22
Oil and gas segment earnings in 2012 were $7.1 billion

compared to $10.2 billion in 2011. The decrease reflected asset

impairments and related items, lower NGL and natural gas prices,

and higher depreciation depletion and amortization (DD&A) rates,

maintenance activity and field support costs and exploration expense,

partially offset by higher oil prices and domestic volumes.

Average production costs for 2012, excluding taxes other than on

income, were $14.99 per BOE, compared to $12.84 per BOE for 2011.

The increase reflected higher maintenance activities and field support

costs. The fourth quarter of 2012 production costs were $14.95 per

barrel, which was $1.04 per barrel lower than the third quarter of

2012 level. These reductions occurred during the course of the fourth

quarter, and the 2012 year-end exit rate on a per barrel basis was

lower than the fourth quarter 2011 average and well below the fourth

quarter 2012 level. These reductions are expected to continue into

2013, reflecting planned improvements in operational efficiencies

over many cost categories.

Average daily oil and gas production volumes were 766,000 BOE

for 2012, compared to 733,000 BOE for 2011. Occidental's domestic

production increased by 9 percent, while total company production

increased by 5 percent. Dolphin's full cost recovery of pre-startup

capital, which reduced production, was the only operation where

PSCs and similar contracts had an appreciable effect on 2012

production volumes. Average daily sales volumes were 764,000 BOE

in the twelve months of 2012, compared with 731,000 BOE for the

same period in 2011.

Oil and gas segment earnings in 2011 were $10.2 billion

compared to $7.2 billion in 2010. The increase reflected higher oil and

NGL prices and volumes, partially offset by higher DD&A rates and

higher operating costs, including higher field support, workover and

well maintenance expenses driven by Occidental’s program to

increase production at current high oil prices.

Average daily oil and gas production volumes were 733,000 BOE

for 2011, compared with 711,000 BOE for 2010. The increase was

mainly due to acquisitions in South Texas, California and the

Williston Basin and higher production in Oman’s Mukhaizna Field

and Iraq, which were partially offset by lower production in Libya.

Production was negatively impacted in the Middle East/North Africa,

Colombia and Long Beach by higher year-over-year average oil prices

affecting PSCs by 18,000 BOE per day. Average daily sales volumes

were 731,000 BOE in the twelve months of 2011, compared with

705,000 BOE for 2010.

Oil and gas segment earnings in 2012 included pre-tax charges

of $1.7 billion for the impairment of domestic gas assets and related

items.

Oil and gas segment earnings in 2011 included pre-tax charges

of $35 million related to exploration write-offs in Libya and $29 million

related to Colombia net worth tax, as well as a pre-tax gain for sale of

an interest in a Colombian pipeline of $22 million.

Chemical

In millions 2012 2011 2010

Segment Sales $ 4,580 $ 4,815 $ 4,016

Segment Earnings $ 720 $ 861 $ 438

Capital Expenditures $ 357 $ 234 $ 237

Chemical segment earnings were $720 million in 2012,

compared to $861 million in 2011. The reduction was primarily the

result of lower margins due to weaker economic conditions in Europe

and Asia and increased competitive activity from these regions. The

calcium chloride and potassium hydroxide businesses were also

negatively impacted by a mild winter and drought conditions in the

United States.

Chemical segment earnings were $861 million in 2011, compared

to $438 million in 2010. The 2011 results reflected strong export sales

and higher margins resulting from higher demand across most

products.

The increase in the chemical capital expenditures was mostly

due to the new chlor-alkali plant.

Midstream, Marketing and Other

In millions 2012 2011 2010

Segment Sales $ 1,399 $ 1,447 $ 1,471

Segment Earnings $ 439 $ 448 $ 472

Capital Expenditures $ 1,558 $ 1,089 $ 501

Midstream and marketing segment earnings in 2012 were $439

million, compared to $448 million in 2011. The 2012 results reflected

lower gas processing earnings and improved marketing and trading

performance.

Midstream and marketing segment earnings in 2011 were $448

million, compared to $472 million in 2010. The 2011 results reflected

lower gas processing margins, partially offset by improved marketing

and trading performance.

The increase in the midstream and marketing capital

expenditures was almost entirely due to the Al Hosn gas project.

23
SIGNIFICANT ITEMS AFFECTING EARNINGS

The following table sets forth, for the years ended December 31,

2012, 2011 and 2010, significant transactions and events affecting

Occidental’s earnings that vary widely and unpredictably in nature,

timing and amount:

Significant Items Affecting Earnings

Benefit (Charge) (in millions) 2012 2011 2010

OIL AND GAS

Asset impairments and related items $ (1,731) $ — $ (275)

Libya exploration write-off — (35) —

Gains on sale of Colombian pipeline interest — 22 —

Foreign tax — (29) —

Total Oil and Gas $ (1,731) $ (42) $ (275)

CHEMICAL

No significant items affecting earnings $ — $ — $ —

Total Chemical $ — $ — $ —

MIDSTREAM AND MARKETING

No significant items affecting earnings $ — $ — $ —

Total Midstream and Marketing $ — $ — $ —

CORPORATE

Litigation reserves $ (20) $ — $ —

Premium on debt extinguishments — (163) —

State income tax charge — (33) —

Foreign tax credit carry-forwards — — 80

Tax effect of pre-tax adjustments 636 50 100

Discontinued operations, net of tax (a) (37) 131 (39)

Total Corporate $ 579 $ (15) $ 141

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

Argentine operations.

TAXES

Deferred tax liabilities, net of deferred tax assets of $2.0 billion,

were $5.8 billion at December 31, 2012. The current portion of the

deferred tax assets of $250 million is included in other current assets.

The deferred tax assets, net of allowances, are expected to be realized

through future operating income and reversal of temporary

differences.

Worldwide Effective Tax Rate

The following table sets forth the calculation of the worldwide

effective tax rate for income from continuing operations:

$ in millions 2012 2011 2010

EARNINGS

Oil and Gas $ 7,095 $ 10,241 $ 7,151

Chemical 720 861 438

Midstream and Marketing 439 448 472

Unallocated Corporate Items (501) (709) (497)

Pre-tax income 7,753 10,841 7,564

Income tax expense

Federal and State 694 1,795 1,087

Foreign 2,424 2,406 1,908

Total income tax expense 3,118 4,201 2,995

Income from continuing operations $ 4,635 $ 6,640 $ 4,569

Worldwide effective tax rate 40% 39% 40%

Occidental’s 2012 worldwide tax rate was 40 percent, slightly

higher than 2011 and comparable to 2010 due to higher proportionate

foreign pre-tax income in 2012. The 2011 income tax expense

included a net $21 million charge for out-of-period state income taxes.

The 2010 income tax expense included an $80 million benefit related

to foreign tax credit carryforwards.

A deferred tax liability has not been recognized for temporary

differences related to unremitted earnings of certain consolidated

foreign subsidiaries as it is Occidental’s intention, generally, to

reinvest such earnings permanently. If the earnings of these foreign

subsidiaries were not indefinitely reinvested, the additional deferred

tax liability required would be immaterial, assuming utilization of

available foreign tax credits.

CONSOLIDATED RESULTS OF OPERATIONS

Changes in components of Occidental's results of operations are

discussed below:

Selected Revenue and Other Income Items

In millions 2012 2011 2010

Net sales $ 24,172 $ 23,939 $ 19,045

Interest, dividends and other income $ 81 $ 180 $ 112

The increase in net sales in 2012, compared to 2011, was due to

higher oil volumes and prices, partially offset by lower gas and NGL

prices and lower prices and volumes across most chemical products.

The increase in net sales in 2011, compared to 2010, was due to

higher oil and NGL prices, higher oil and gas segment volumes and

higher sales, including higher export sales, across most chemical

products.

Price and volume changes in the oil and gas segment generally

represent a substantially larger portion of the overall change in net

sales than the chemical and midstream and marketing segments.

24
Selected Expense Items

In millions 2012 2011 2010

Cost of sales (a) $ 7,844 $ 7,385 $ 6,112

Selling, general and administrative

and other operating expenses $ 1,602 $ 1,523 $ 1,396

Depreciation, depletion and

amortization $ 4,511 $ 3,591 $ 3,153

Taxes other than on income $ 680 $ 605 $ 484

Exploration expense $ 345 $ 258 $ 262

Asset impairments and related items $ 1,751 $ — $ 275

Interest and debt expense, net $ 130 $ 298 $ 116

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

million in 2010.

Cost of sales increased in 2012, compared to 2011, due to higher

oil and gas volumes and operating costs, mostly resulting from higher

maintenance activity and field support costs, partially offset by lower

feedstock and energy costs in the chemical segment.

Cost of sales increased in 2011, compared to 2010, due to higher

oil and gas volumes, higher oil and gas operating costs, mostly

resulting from higher workover and well maintenance activity and

higher feedstock costs in the chemical segment.

Selling, general and administrative and other operating

expenses increased in 2012 due to higher headcount, partially offset

by lower equity compensation expense and the Colombia net worth

tax which increased the 2011 costs.

Selling, general and administrative and other operating

expenses increased in 2011 due to higher headcount and

environmental remediation expense and the Colombia net worth tax.

DD&A increased in each year from 2010 to 2012, generally due to

higher DD&A rates and volumes in the oil and gas segment. The

DD&A rate is expected to further increase in 2013.

Taxes other than on income increased in each year from 2010 to

2012, due to higher domestic oil volumes and prices and higher

domestic ad valorem taxes resulting from higher property values.

Asset impairments and related items in 2012 were almost all in

Midcontinent, over 90 percent of which were related to natural gas

properties that were acquired more than four years ago on average

when gas prices were over $6 per Mcf.

Asset impairments and related items in 2010 predominately

related to gas properties in the Rocky Mountain region.

Interest and debt expense, net, in 2011, included the $163

million early debt extinguishment charge recorded in the first quarter

of 2011.

Selected Other Items

Income/(expense) (in millions) 2012 2011 2010

Provision for income taxes $ (3,118) $ (4,201) $ (2,995)

Income from equity investments $ 363 $ 382 $ 277

Discontinued operations, net $ (37) $ 131 $ (39)

Net income attributable to

noncontrolling interest $ — $ — $ 72

Provision for income taxes decreased in 2012, compared to 2011,

due to lower pre-tax income, partially offset by a slightly higher

effective tax rate. The higher tax rate was due to higher proportional

foreign pre-tax income in 2012, compared to 2011.

Provision for income taxes increased in 2011, compared to 2010,

due to higher pre-tax income, partially offset by a slightly lower

effective tax rate. The lower tax rate was due to higher proportional

domestic pre-tax income in 2011, compared to 2010.

Income from equity investment in 2012 was comparable to 2011.

Income from equity investments increased in 2011, compared to

2010, due to an additional investment in the Plains Pipeline in late

2010 and its higher earnings.

Discontinued operations, net, in 2011, included the $144 million

after-tax gain recorded from the sale of the Argentine operations.

There was no net income attributable to noncontrolling interest in

2012 and 2011 due to the restructuring of Occidental’s Colombian

operations to take a direct working interest in the related assets as of

December 31, 2010.

CONSOLIDATED ANALYSIS OF FINANCIAL POSITION

The changes in select components of Occidental’s balance sheet

are discussed below:

Selected Balance Sheet Components

In millions 2012 2011

CURRENT ASSETS

Cash and cash equivalents $ 1,592 $ 3,781

Trade receivables, net 4,916 5,395

Inventories 1,344 1,069

Other current assets 1,640 1,297

Total current assets $ 9,492 $ 11,542

Investments in unconsolidated entities $ 1,894 $ 2,072

Property, plant and equipment, net $ 52,064 $ 45,684

Long-term receivables and other assets, net $ 760 $ 746

CURRENT LIABILITIES

Current maturities of long-term debt $ 600 $ —

Accounts payable 4,708 5,304

Accrued liabilities 1,966 2,533

Domestic and foreign income taxes 16 110

Total current liabilities $ 7,290 $ 7,947

Long-term debt, net $ 7,023 $ 5,871

Deferred credits and other liabilities-income taxes $ 6,039 $ 4,846

Deferred credits and other liabilities-other $ 3,810 $ 3,760

Stockholders’ equity $ 40,048 $ 37,620

25
Assets

See "Liquidity and Capital Resources — Cash Flow Analysis" for

discussion about the change in cash and cash equivalents.

The decrease in trade receivables, net, was due to lower oil and

gas prices at the end of 2012, compared to the end of 2011. The

increase in inventories was primarily due to higher volumes of oil in

storage and materials and supplies held at the end of 2012, compared

to the end of 2011. The increase in other current assets in 2012

resulted from an increase in tax receivables. The decrease in

investments in unconsolidated entities was mostly due to higher

distributions received in the current year. The increase in PP&E, net,

was due to capital expenditures and acquisitions of oil and gas

properties, partially offset by DD&A and asset impairments.

Liabilities and Stockholders' Equity

The increase in current maturities of long-term debt was due to

debt maturing in 2013. The decrease in accounts payable reflected

lower oil and gas prices in the marketing and trading operations

during the fourth quarter of 2012 and lower oil and gas spending

levels at the end of 2012, compared to the same periods in 2011. The

decrease in accrued liabilities was mostly due to the acceleration of

the fourth quarter 2012 dividend payment, which normally would

have been accrued as of year end but paid in the first quarter of the

following year. The increase in long-term debt, net, was due to the

June 2012 issuance of $1.75 billion of senior unsecured notes,

partially offset by debt maturities that became current at the end of

2012. The increase in deferred and other domestic and foreign income

taxes was mainly due to accelerated tax depreciation of the capital

expenditures in 2012. The increase in stockholders' equity reflected

net income for 2012, partially offset by dividends and treasury stock

purchases.

LIQUIDITY AND CAPITAL RESOURCES

At December 31, 2012, Occidental had approximately $1.6 billion

in cash on hand, a substantial majority of which is held domestically.

Income and cash flows are largely dependent on the oil and gas

segment's prices and sales volumes. Occidental believes that cash on

hand and cash generated from operations will be sufficient to fund its

operating needs and planned capital expenditures, dividends and

any debt payments.

Occidental has a bank credit facility (Credit Facility) with a $2.0

billion commitment expiring in 2016. No amounts have been drawn

under this Credit Facility. Up to $1.0 billion of the Credit Facility is

available in the form of letters of credit. Borrowings under the Credit

Facility bear interest at various benchmark rates, including LIBOR,

plus a margin based on Occidental's senior debt ratings. Additionally,

Occidental paid average annual facility fees of 0.08 percent in 2012

on the total commitment amounts of the Credit Facility.

The Credit Facility provides for the termination of loan

commitments and requires immediate repayment of any outstanding

amounts if certain events of default occur. The Credit Facility and

other debt agreements do not contain

material adverse change clauses or debt ratings triggers that could

restrict Occidental's ability to borrow or that would permit lenders to

terminate their commitments or accelerate debt.

As of December 31, 2012, under the most restrictive covenants of

its financing agreements, Occidental had substantial capacity for

additional unsecured borrowings, the payment of cash dividends and

other distributions on, or acquisitions of, Occidental stock.

Occidental has a shelf registration statement that facilitates future

issuances of securities. In June 2012, Occidental issued $1.75 billion

of debt which comprised $1.25 billion of 2.70-percent senior

unsecured notes due 2023 and $500 million of 1.50-percent senior

unsecured notes due 2018. Occidental received net proceeds of

approximately $1.74 billion. Interest on the notes will be payable

semi-annually in arrears in February and August for each series of

notes.

Occidental, from time to time, may access and has accessed debt

markets for general corporate purposes, including acquisitions.

Cash Flow Analysis

In millions 2012 2011 2010

Net cash provided by operating activities $ 11,312 $ 12,281 $ 9,566

Although net income decreased by $2.2 billion for the twelve

months ended December 31, 2012, compared to the same period of

2011, net cash provided by operating activities only decreased by $1.0

billion for this period. Compared to 2011, net income in 2012 included

much larger non-cash charges, which reduced net income but not

cash provided by operating activities. These non-cash charges mainly

comprised asset impairments and higher DD&A. Working capital

changes in 2012 further reduced cash flow from operations by

approximately $0.8 billion, compared to 2011.

Additionally, operating cash flows in 2012, compared to 2011,

reflected lower domestic gas and worldwide NGL prices, by 35 percent

and 19 percent, respectively, and higher maintenance activity and

field support costs, partially offset by higher domestic oil volumes and

2-percent higher worldwide oil prices. The positive cash-flow impact of

the oil price change was more than offset by the negative effect of

significant declines in gas and NGL prices. The decrease in operating

cash flows in 2012, compared to 2011, also reflected lower chemical

margins, primarily due to weaker economic conditions in Europe and

Asia.

Other cost elements, such as labor costs and overhead, are not

significant drivers of changes in cash flow because they are relatively

stable within a narrow range over the short to intermediate term.

Changes in these costs had a much smaller effect on cash flow than

the changes in oil prices and volumes and gas and NGL prices.

The most important sources of the increase in operating cash flow

in 2011, compared to 2010, were higher worldwide oil and NGL prices

and volumes. In 2011,

26
compared to 2010, Occidental’s global realized oil and NGL prices

increased 30 percent and 23 percent, respectively. In 2011,

Occidental’s oil and NGL production accounted for 71 percent of its

total net sales. Increases in field support, workover and well

maintenance costs in 2011, compared to 2010, partially offset the

increases in prices and volumes. The increase in operating cash flows

in 2011, compared to 2010, also reflected high chemical product prices

and margins for most products.

The impact of the chemical and the midstream and marketing

segments on overall cash flows is generally less significant than the

impact of the oil and gas segment because the chemical and

midstream and marketing segments are significantly smaller.

Other non-cash charges to income in 2012, 2011 and 2010

included charges for stock-based compensation plans and asset

retirement obligation accruals.

Operating cash flows for discontinued operations include the

Argentine operations through the date they were sold in February

2011.

In millions 2012 2011 2010

Capital expenditures

Oil and Gas $ (8,220) $ (6,145) $ (3,166)

Chemical (357) (234) (237)

Midstream and Marketing (1,558) (1,089) (501)

Corporate (91) (50) (36)

Total (10,226) (7,518) (3,940)

Other investing activities, net (2,429) (4,955) (4,940)

Net cash used by investing activities –

continuing operations (12,655) (12,473) (8,880)

Investing cash flow from discontinued

operations — 2,570 (415)

Net cash used by investing activities $ (12,655) $ (9,903) $ (9,295)

The increase in capital expenditures of $2.7 billion from 2011 to

2012 was mainly due to the $2.1 billion increase in oil and gas

expenditures, a majority of which was in domestic properties, such as

Permian and California, as well as increases throughout the Middle

East. Occidental’s United States average operated-rig activity

increased 25 percent from 51 rigs in 2011 to 64 rigs in 2012. The rig

count was 41 at the end of 2012. The increase in the midstream and

marketing capital expenditures was almost entirely due to the Al Hosn

gas project.

Occidental’s capital spending is expected to decrease in 2013 to

approximately $9.6 billion and will be focused on increasing oil

production and ensuring Occidental's returns remain well above its

costs of capital given current prices and the cost environment. The

reduction in capital will come entirely from the oil and gas segment,

almost all of which will be in Occidental's domestic operations.

Occidental expects that a meaningful portion of the capital reduction

will come from efficiencies in its drilling program. During the fourth

quarter of 2012, Occidental embarked on an efficiency program that,

among other things, targeted a 15-percent reduction in its drilling

costs. Through the end of 2012 and early 2013, Occidental believes

that it has already achieved about half of the targeted savings with

further improvements expected during the remainder of 2013.

Occidental believes it will be able to grow oil

production while reducing capital expenditures because it expects

much of the capital reduction to come from efficiencies and not

reduced activity. It expects only a modest impact on natural gas and

NGL production from reduced gas drilling. The midstream and

marketing segment capital spending will increase mainly for the

BridgeTex pipeline. The 2013 capital program is expected to be

approximately 75 percent in oil and gas, 11 percent in the Al Hosn gas

project, 9 percent in domestic midstream and marketing and the

remainder in the chemical segment.

Occidental expects to spend about 25 percent of its total capital

expenditures on projects that will begin contributing to its earnings

and cash flow over the next several years. These projects include the

Al Hosn gas project, the BridgeTex pipeline, expansion of gas and

CO2 processing plants and a new chlor-alkali plant in the chemical

business. As of December 31, 2012, the accumulated balance of such

project costs that will contribute to earnings in future years, excluding

costs of undeveloped acreage, was approximately $3.1 billion.

Occidental expects this balance to grow by the end of 2013 before

these investments start generating returns in 2014.

The 2012 other investing activities, net amount included $2.5

billion in cash payments for the acquisitions of businesses and assets,

largely consisting of various interests in domestic oil and gas

properties in the Permian Basin, the Williston Basin, California and

South Texas. Also included in 2012 investing activities was

approximately $190 million of cash dividends received as investment

returns.

The increase in capital expenditures of $3.6 billion from 2010 to

2011 was mainly due to the $3.0 billion increase in oil and gas

expenditures, which reflected Occidental’s share of development costs

in Oman and Bahrain, and higher spending in domestic properties in

California, the Permian Basin, South Texas and the Williston Basin.

Occidental’s United States operated rig activity increased 89 percent

from 38 rigs at year-end 2010 to 72 rigs at year-end 2011.

The 2011 other investing activities, net amount included $4.9

billion in cash payments for the acquisitions of businesses and assets,

including various interests in domestic oil and gas properties, in

operated, producing and non-producing properties in California and

the Permian and Williston Basins for approximately $2.4 billion,

properties in South Texas for $1.8 billion and $0.5 billion for

Occidental’s share of pre-acquisition development expenditures

incurred by the Al Hosn gas project.

The 2010 other investing activities, net amount included $4.9

billion in cash payments for the acquisitions of businesses and assets,

including acquisitions of various interests in domestic oil and gas

properties, in operated, producing and non-producing properties in

the Permian Basin, Midcontinent region and California, for

approximately $2.5 billion, properties in North Dakota for

approximately $1.4 billion, additional interests in Plains Pipeline for

approximately $430 million and the remaining 50-percent interest in

EHP for approximately $175 million, as well as foreign contract

payments of approximately $225 million.

27
Investing cash flow from discontinued operations included $2.6

billion of cash received from the sale of the Argentine operations in

2011, and capital expenditures of $310 million in 2010.

Commitments at December 31, 2012, for major fixed and

determinable capital expenditures were approximately $2.2 billion,

which will be due in 2013 and beyond. Occidental expects to fund

these commitments and capital expenditures with cash from

operations.

In millions 2012 2011 2010

Net cash (used) provided by financing

activities $ (846) $ (1,175) $ 1,083

The 2012 net cash used by financing activities included net

proceeds of approximately $1.7 billion from the June 2012 issuance of

senior unsecured notes. Common stock dividends paid increased by

$0.7 billion to $2.1 billion in 2012, which included the accelerated

payment of the fourth quarter dividend. In addition, purchases of

treasury stock increased from $274 million in 2011 to $583 million.

The 2011 amount included net proceeds of approximately $2.1

billion from the August 2011 issuance of senior unsecured notes and

financing cash flow use of $1.5 billion to retire other long-term debt.

Common stock dividends paid increased from $1.1 billion in 2010 to

$1.4 billion in 2011. In addition, purchases of treasury stock increased

from $67 million in 2010 to $274 million in 2011.

The 2010 amount included net proceeds of approximately $2.6

billion from the issuance of senior unsecured notes and financing

cash flow use of $311 million to retire other long-term debt.

OFF-BALANCE-SHEET ARRANGEMENTS

The following is a description of the business purpose and nature

of Occidental's off-balance-sheet arrangements.

Guarantees

Occidental has guaranteed certain equity investees' debt and

has entered into various other guarantees including performance

bonds, letters of credit, indemnities and commitments provided by

Occidental to third parties, mainly to provide assurance that OPC or

its subsidiaries and affiliates will meet their various obligations

(guarantees). As of December 31, 2012, Occidental’s guarantees were

not material and a substantial majority consisted of limited recourse

guarantees on approximately $370 million of Dolphin’s debt, for which

the fair value was immaterial.

See "Oil and Gas Segment — Business Review — Qatar" and

“Segment Results of Operations” for further information about

Dolphin.

Leases

Occidental has entered into various operating lease agreements,

mainly for transportation equipment, power plants, machinery,

terminals, storage facilities, land and office space. Occidental leases

assets when leasing offers greater operating flexibility. Lease

payments are generally expensed as part of cost of sales and selling,

general and administrative expenses. For more information, see

"Contractual Obligations."

CONTRACTUAL OBLIGATIONS

The table below summarizes and cross-references Occidental’s

contractual obligations. This summary indicates on- and off-balancesheet obligations as of December 31, 2012.

Contractual Obligations

(in millions)

Payments Due by Year

Total 2013

2014

and

2015

2016

and

2017

2018

and

thereafter

On-Balance Sheet

Long-term debt (Note

5) (a) $ 7,654 $ 600 $ — $ 2,700 $ 4,354

Other long-term

liabilities (b) 2,202 276 477 200 1,249

Off-Balance Sheet

Operating leases (Note

6) 976 158 211 147 460

Purchase obligations

(c) 8,723 2,745 2,065 923 2,990

Total $ 19,555 $ 3,779 $ 2,753 $ 3,970 $ 9,053

(a) Excludes unamortized debt discount and interest on the debt. As of

December 31, 2012, interest on long-term debt totaling $1.7 billion is payable

in the following years (in millions): 2013 - $230, 2014 and 2015 - $443, 2016

and 2017 - $341, 2018 and thereafter - $658.

(b) Includes obligations under postretirement benefit and deferred compensation

plans, as well as certain accrued liabilities.

(c) Amounts include payments which will become due under long-term

agreements to purchase goods and services used in the normal course of

business to secure terminal and pipeline capacity, drilling rigs and

services, CO2 , electrical power, steam and certain chemical raw materials.

Amounts exclude certain oil purchase obligations related to marketing and

trading activities for which there are no minimum purchase requirements. 

Long-term purchase contracts are discounted at a 3.0-percent discount rate.

Delivery Commitments

Occidental has made commitments to certain refineries and other

buyers to deliver a portion of its oil, gas and NGL production. The total

amount contracted to be delivered, a substantial majority of which is

in the United States, is approximately 65 million barrels of oil through

2019, 73 billion cubic feet of gas through 2016 and 3 million barrels of

NGLs through 2013. The price for these deliveries is set at the time of

delivery of the product. Occidental has significantly more production

capacity than the amounts committed and none of the commitments in

any given year are material. In addition, Occidental has the ability to

secure additional volumes in the case of a shortfall.

28
LAWSUITS, CLAIMS AND CONTINGENCIES

OPC or certain of its subsidiaries are involved, in the normal

course of business, in lawsuits, claims and other legal proceedings

that seek, among other things, compensation for alleged personal

injury, breach of contract, property damage or other losses, punitive

damages, civil penalties, or injunctive or declaratory relief. OPC or

certain of its subsidiaries also are involved in proceedings under the

Comprehensive Environmental Response, Compensation, and

Liability Act (CERCLA) and similar federal, state, local and foreign

environmental laws. These environmental proceedings seek funding

or performance of remediation and, in some cases, compensation for

alleged property damage, punitive damages, civil penalties and

injunctive relief. Usually OPC or such subsidiaries are among many

companies in these environmental proceedings and have to date

been successful in sharing response costs with other financially

sound companies. Further, some lawsuits, claims and legal

proceedings involve acquired assets with respect to which third

parties retain liability or indemnify Occidental for conditions that

existed prior to purchase.

Occidental accrues reserves for currently outstanding lawsuits,

claims and proceedings when it is probable that a liability has been

incurred and the liability can be reasonably estimated. Occidental

has disclosed its reserve balances for environmental matters. Reserve

balances for other matters as of December 31, 2012 and 2011, were

not material to Occidental's consolidated balance sheets. Occidental

also evaluates the amount of reasonably possible losses that it could

incur as a result of the matters mentioned above. Occidental has

disclosed its range of reasonably possible additional losses for sites

where it is a participant in environmental remediation. Occidental

believes that other reasonably possible losses that it could incur in

excess of reserves accrued on the balance sheet would not be

material to its consolidated financial position or results of operations.

Environmental matters are further discussed under the caption

"Environmental Liabilities and Expenditures" below.

On October 5, 2012, an Arbitral Tribunal of the International

Centre for Settlement of Investment Disputes (ICSID), an agency of

the World Bank, found that Ecuador violated the United States -

Ecuador Bilateral Investment Treaty in 2006 when it terminated

Occidental’s Block 15 concession. The Tribunal ordered Ecuador to

pay $1.77 billion, plus interest, in damages. Ecuador has filed an

application asking ICSID to annul the damage award; it could take

over a year for ICSID to rule on Ecuador’s application for annulment.

Pursuant to a 2000 Farmout Agreement, Andes Petroleum is entitled

to 40% of any net amount which Occidental recovers from Ecuador in

this ICSID proceeding. The effect, if any, on the financial statements

will be recognized upon final resolution of this matter.

During the course of its operations, Occidental is subject to audit

by tax authorities for varying periods in various federal, state, local

and foreign tax jurisdictions. Although taxable years through 2009 for

United States federal income tax purposes have been audited by the

United States Internal Revenue Service (IRS) pursuant to

its Compliance Assurance Program, subsequent taxable years are

currently under review. Additionally, in December 2012, Occidental

filed United States federal refund claims for tax years 2008 and 2009

which are subject to IRS review. Taxable years from 2000 through the

current year remain subject to examination by foreign and state

government tax authorities in certain jurisdictions. In certain of these

jurisdictions, tax authorities are in various stages of auditing

Occidental's income taxes. During the course of tax audits, disputes

have arisen and other disputes may arise as to facts and matters of

law. Occidental believes that the resolution of outstanding tax matters

would not have a material adverse effect on its consolidated financial

position or results of operations.

OPC, its subsidiaries or both have indemnified various parties

against specified liabilities those parties might incur in the future in

connection with purchases and other transactions that they have

entered into with Occidental. These indemnities usually are

contingent upon the other party incurring liabilities that reach

specified thresholds. As of December 31, 2012, Occidental is not

aware of circumstances that it believes would reasonably be expected

to lead to indemnity claims that would result in payments materially in

excess of reserves.

ENVIRONMENTAL LIABILITIES AND EXPENDITURES

Occidental’s operations are subject to stringent federal, state,

local and foreign laws and regulations related to improving or

maintaining environmental quality. Occidental’s environmental

compliance costs have generally increased over time and are

expected to rise in the future. Occidental factors environmental

expenditures for its operations into its business planning process as

an integral part of producing quality products responsive to market

demand.

Environmental Remediation

The laws that require or address environmental remediation,

including CERCLA and similar federal, state, local and foreign laws,

may apply retroactively and regardless of fault, the legality of the

original activities or the current ownership or control of sites. OPC or

certain of its subsidiaries participate in or actively monitor a range of

remedial activities and government or private proceedings under

these laws with respect to alleged past practices at operating, closed

and third-party sites. Remedial activities may include one or more of

the following: investigation involving sampling, modeling, risk

assessment or monitoring; cleanup measures including removal,

treatment or disposal; or operation and maintenance of remedial

systems. The environmental proceedings seek funding or

performance of remediation and, in some cases, compensation for

alleged property damage, punitive damages, civil penalties,

injunctive relief and government oversight costs.

As of December 31, 2012, Occidental participated in or monitored

remedial activities or proceedings at 161 sites. The following table

presents Occidental’s environmental remediation reserves as of

December 31, 2012, 2011 and 2010, grouped as environmental

remediation sites listed or proposed for listing by the U.S.

Environmental Protection

29
Agency on the CERCLA National Priorities List (NPL sites) and three

categories of non-NPL sites — third-party sites, Occidental-operated

sites and closed or non-operated Occidental sites.

$ amounts

in millions 2012 2011 2010

# of

Sites

Reserve

Balance

# of

Sites

Reserve

Balance

# of

Sites

Reserve

Balance

NPL sites 35 $ 54 36 $ 63 38 $ 56

Third-party sites 75 84 73 88 83 91

Occidental-operated

sites 22 123 22 120 20 122

Closed or nonoperated

Occidental sites 29 83 29 89 29 97

Total 161 $ 344 160 $ 360 170 $ 366

As of December 31, 2012, Occidental’s environmental reserves

exceeded $10 million each at 12 of the 161 sites described above, and

112 of the sites had reserves from $0 to $1 million each.

As of December 31, 2012, two landfills in western New York

owned by Occidental accounted for 73 percent of its reserves

associated with NPL sites. In connection with a 1986 acquisition,

Maxus Energy Corporation has retained the liability and indemnified

Occidental for 14 of the remaining NPL sites.

As of December 31, 2012, Maxus has also retained the liability

and indemnified Occidental for 8 of the 75 third-party sites. Two of the

remaining 67 third-party sites — a former copper mining and smelting

operation in Tennessee and a containment and removal project in

Tennessee — accounted for 43 percent of Occidental’s reserves

associated with these sites.

Five sites — chemical plants in Kansas, Louisiana, Texas and

New York and a group of oil and gas properties in the southwestern

United States — accounted for 70 percent of the reserves associated

with the Occidental-operated sites.

Three other sites — former chemical plants in Tennessee and

Delaware and a closed coal mine in Pennsylvania — accounted for 55

percent of the reserves associated with closed or non-operated

Occidental sites.

Environmental reserves vary over time depending on factors such

as acquisitions or dispositions, identification of additional sites and

remedy selection and implementation. The following table presents

environmental reserve activity for the past three years:

In millions 2012 2011 2010

Balance — Beginning of Year $ 360 $ 366 $ 403

Remediation expenses and interest accretion 56 53 26

Changes from acquisitions/dispositions — 14 3

Payments (72) (73) (66)

Balance — End of Year $ 344 $ 360 $ 366

Based on current estimates, Occidental expects to expend funds

corresponding to approximately half of the current environmental

reserves at the sites described above over the next four years and the

balance at these

sites over the subsequent 10 or more years. Occidental believes its

range of reasonably possible additional losses beyond those liabilities

recorded for environmental remediation at these sites could be up to

$375 million. See "Critical Accounting Policies and Estimates —

Environmental Liabilities and Expenditures" for additional

information.

Occidental’s environmental costs, some of which include

estimates, are presented below for each segment for each of the years

ended December 31:

In millions 2012 2011 2010

Operating Expenses

Oil and Gas $ 160 $ 158 $ 108

Chemical 70 68 72

Midstream and Marketing 20 21 13

$ 250 $ 247 $ 193

Capital Expenditures

Oil and Gas $ 122 $ 110 $ 72

Chemical 18 15 19

Midstream and Marketing 12 15 13

$ 152 $ 140 $ 104

Remediation Expenses

Corporate $ 56 $ 52 $ 25

Operating expenses are incurred on a continual basis. Capital

expenditures relate to longer-lived improvements in currently

operating properties. Remediation expenses relate to existing

conditions from past operations.

Occidental presently estimates capital expenditures for

environmental compliance of approximately $ 130 million for 2013.

FOREIGN INVESTMENTS

Many of Occidental’s assets are located outside North America. At

December 31, 2012, the carrying value of Occidental’s assets in

countries outside North America aggregated approximately $12.3

billion, or approximately 19 percent of Occidental’s total assets at that

date. Of such assets, approximately $10.6 billion are located in the

Middle East/North Africa and approximately $1.6 billion are located in

Latin America. For the year ended December 31, 2012, net sales

outside North America totaled $8.8 billion, or approximately 36 percent

of total net sales.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The process of preparing financial statements in accordance with

generally accepted accounting principles requires Occidental's

management to make informed estimates and judgments regarding

certain items and transactions. Changes in facts and circumstances or

discovery of new information may result in revised estimates and

judgments, and actual results may differ from these estimates upon

settlement but generally not by material amounts. There has been no

material change to Occidental's critical accounting policies over the

past three years. The selection and development of these policies and

estimates have been discussed with the Audit Committee of the Board

of Directors. Occidental considers the following to be its most critical

accounting policies and estimates that involve management's

judgment.

30
Oil and Gas Properties

The carrying value of Occidental’s property, plant and equipment

(PP&E) represents the cost incurred to acquire or develop the asset,

including any asset retirement obligations and capitalized interest,

net of accumulated depreciation, depletion and amortization (DD&A)

and net of any impairment charges. For assets acquired, PP&E cost is

based on fair values at the acquisition date. Asset retirement

obligations and interest costs incurred in connection with qualifying

capital expenditures are capitalized and amortized over the lives of

the related assets.

Occidental uses the successful efforts method to account for its oil

and gas properties. Under this method, Occidental capitalizes costs of

acquiring properties, costs of drilling successful exploration wells and

development costs. The costs of exploratory wells are initially

capitalized pending a determination of whether proved reserves have

been found. If proved reserves have been found, the costs of

exploratory wells remain capitalized. Otherwise, Occidental charges

the costs of the related wells to expense. In some cases, a

determination of proved reserves cannot be made at the completion of

drilling, requiring additional testing and evaluation of the wells.

Occidental generally expenses the costs of such exploratory wells if a

determination of proved reserves has not been made within a 12-

month period after drilling is complete.

Occidental expenses annual lease rentals and geological,

geophysical and seismic costs as incurred.

Occidental expenses the costs of injectants used in production.

Occidental determines depreciation and depletion of oil and gas

producing properties by the unit-of-production method. It amortizes

acquisition costs over total proved reserves and capitalized

development and successful exploration costs over proved developed

reserves.

Proved oil and gas reserves (as defined in the Securities and

Exchange Commission's Regulation S-X, Rule 4-10(a)) are those

quantities of oil and gas, which, by analysis of geoscience and

engineering data, can be estimated with reasonable certainty to be

economically producible—from a given date forward, from known

reservoirs, and under existing economic conditions, operating

methods, and government regulations—prior to the time at which

contracts providing the right to operate expire, unless evidence

indicates that renewal is reasonably certain, regardless of whether

deterministic or probabilistic methods are used for the estimation.

Occidental has no proved oil and gas reserves for which the

determination of economic producibility is subject to the completion of

major additional capital expenditures.

Several factors could change Occidental’s proved oil and gas

reserves. For example, Occidental receives a share of production from

PSCs to recover its costs and generally an additional share for profit.

Occidental’s share of production and reserves from these contracts

decreases when oil prices rise and increases when oil prices decline.

Overall, Occidental’s net economic benefit from these contracts is

greater at higher oil prices. In other cases, particularly with long-lived

properties, lower product prices

may lead to a situation where production of a portion of proved

reserves becomes uneconomical. For such properties, higher product

prices typically result in additional reserves becoming economical.

Estimation of future production and development costs is also subject

to change partially due to factors beyond Occidental's control, such as

energy costs and inflation or deflation of oil field service costs. These

factors, in turn, could lead to changes in the quantity of proved

reserves. Additional factors that could result in a change of proved

reserves include production decline rates and operating performance

differing from those estimated when the proved reserves were initially

recorded. In 2012, revisions of previous estimates provided a net

183 million BOE reduction to proved reserves, which amounted to less

than 6 percent of Occidental's total reserves as of December 31, 2012.

In 2012, revisions related to price for the company as a whole

were negative. A substantial majority of such revisions related to

Occidental's domestic gas reserves and resulted from lower domestic

gas prices. These lower prices and the resulting changes in

Occidental's plans for drilling on gas properties constituted a majority

of its total revisions. To the extent gas prices recover in the future, a

portion of these reserves will be reinstated. If natural gas prices

decrease further for an extended period, domestic gas reserves could

experience additional negative price revisions.

The most significant financial statement effect from a change in

Occidental's oil and gas reserves would be to the DD&A rate. For

example, a 5-percent increase or decrease in the amount of oil and

gas reserves would change the DD&A rate by approximately $0.80 per

barrel, which would increase or decrease pre-tax income by

approximately $225 million annually at current production rates. The

change in the DD&A rate over the past three years due to revisions of

previous proved reserve estimates has been immaterial.

A portion of the carrying value of Occidental’s oil and gas

properties is attributable to unproved properties. At December 31,

2012, the net capitalized costs attributable to unproved properties

were $4.8 billion. The unproved amounts are not subject to DD&A

until they are classified as proved properties. As exploration and

development work progresses, if reserves on these properties are

proved, capitalized costs attributable to the properties become subject

to DD&A. If the exploration and development work were to be

unsuccessful, or management's plans changed with respect to these

properties, as a result of economic, operating or contractual conditions,

the capitalized costs of the related properties would be expensed. The

timing of any writedowns of these unproved properties, if warranted,

depends upon management's plans, the nature, timing and extent of

future exploration and development activities and their results.

Occidental believes its current plans and exploration and

development efforts will allow it to realize its unproved property

balance.

Additionally, Occidental performs impairment tests with respect to

its proved properties generally when prices decline other than

temporarily, reserve estimates change significantly or other significant

events occur that may

31
impact its ability to realize the recorded asset amounts. Impairment

tests incorporate a number of assumptions involving expectations of

future cash flows, which can change significantly over time. These

assumptions include estimates of future product prices, which

Occidental bases on forward price curves and, when applicable,

contractual prices, estimates of oil and gas reserves and estimates of

future expected operating and development costs.

In the fourth quarter of 2012, impairment charges totaling $1.7

billion pre-tax were taken on certain proved and unproved properties.

Almost all of the charges were for certain properties in Midcontinent,

over 90 percent of which were related to natural gas properties that

were acquired more than four years ago on average when gas prices

were more than $6 per Mcf. These properties were impacted by

persistently low natural gas prices in the United States changing

management's development plans and negative reserve revisions

due to recent well performance. Any impairment loss would be

calculated as the excess of the asset's net book value over its

estimated fair value. Any further sustained declines in gas prices as

well as significant sustained reductions in the prices of other products

may result in additional impairments in the future.

Chemical Assets

Occidental's chemical assets are depreciated using either the

unit-of-production or the straight-line method, based upon the

estimated useful lives of the facilities. The estimated useful lives of

Occidental’s chemical assets, which range from three years to 50

years, are also used for impairment tests. The estimated useful lives

for the chemical facilities are based on the assumption that Occidental

will provide an appropriate level of annual expenditures to ensure

productive capacity is sustained. Such expenditures consist of

ongoing routine repairs and maintenance, as well as planned major

maintenance activities (PMMA). Ongoing routine repairs and

maintenance expenditures are expensed as incurred. PMMA costs

are capitalized and amortized over the period until the next planned

overhaul. Additionally, Occidental incurs capital expenditures that

extend the remaining useful lives of existing assets, increase their

capacity or operating efficiency beyond the original specification or

add value through modification for a different use. These capital

expenditures are not considered in the initial determination of the

useful lives of these assets at the time they are placed into service.

The resulting revision, if any, of the asset’s estimated useful life is

measured and accounted for prospectively.

Without these continued expenditures, the useful lives of these

assets could decrease significantly. Other factors that could change

the estimated useful lives of Occidental’s chemical assets include

sustained higher or lower product prices, which are particularly

affected by both domestic and foreign competition, demand, feedstock

costs, energy prices, environmental regulations and technological

changes.

Occidental performs impairment tests on its chemical assets

whenever events or changes in circumstances lead to a reduction in

the estimated useful lives or estimated future cash flows that would

indicate that the carrying amount may not be recoverable, or when

management’s plans change with respect to those assets. Any

impairment loss would be calculated as the excess of the asset's net

book value over its estimated fair value.

Occidental's net PP&E for the chemical segment is approximately

$2.6 billion and its depreciation expense for 2013 is expected to be

approximately $300 million. The most significant financial statement

impact of a decrease in the estimated useful lives of Occidental's

chemical plants would be on depreciation expense. For example, a

reduction in the remaining useful lives of one year would increase

depreciation and reduce pre-tax earnings by approximately $45

million per year.

Midstream, Marketing and Other Assets

Derivatives are carried at fair value and on a net basis when a

legal right of offset exists with the same counterparty. Occidental

applies hedge accounting when transactions meet specified criteria for

cash-flow hedge treatment and management elects and documents

such treatment. Otherwise, any fair value gains or losses are

recognized in earnings in the current period. For cash-flow hedges,

the gain or loss on the effective portion of the derivative is reported as

a component of other comprehensive income (OCI) with an offsetting

adjustment to the basis of the item being hedged. Realized gains or

losses from cash-flow hedges, and any ineffective portion, are

recorded as a component of net sales in the consolidated statements of

income. Ineffectiveness is primarily created by a basis difference

between the hedged item and the hedging instrument due to location,

quality or grade of the physical commodity transactions. Gains and

losses from derivative instruments are reported net in the consolidated

statements of income. There were no fair value hedges as of and

during the year ended December 31, 2012.

A hedge is regarded as highly effective such that it qualifies for

hedge accounting if, at inception and throughout its life, it is expected

that changes in the fair value or cash flows of the hedged item will be

offset by 80 to 125 percent of the changes in the fair value or cash

flows, respectively, of the hedging instrument. In the case of hedging

a forecast transaction, the transaction must be probable and must

present an exposure to variations in cash flows that could ultimately

affect reported net income or loss. Occidental discontinues hedge

accounting when it determines that a derivative has ceased to be

highly effective as a hedge; when the hedged item matures or is sold

or repaid; or when a forecast transaction is no longer deemed

probable.

32
Occidental's midstream and marketing PP&E is depreciated over

the estimated useful lives of the assets, using either the unit-ofproduction or straight-line method. Occidental performs impairment

tests on its midstream and marketing assets whenever events or

changes in circumstances lead to a reduction in the estimated useful

lives or estimated future cash flows that would indicate that the

carrying amount may not be recoverable, or when management’s

plans change with respect to those assets. Any impairment loss would

be calculated as the excess of the asset's net book value over its

estimated fair value.

Fair Value Measurements

Occidental has categorized its assets and liabilities that are

measured at fair value in a three-level fair value hierarchy, based on

the inputs to the valuation techniques: Level 1 – using quoted prices

in active markets for identical assets or liabilities; Level 2 – using

observable inputs other than quoted prices for identical assets or

liabilities; and Level 3 – using unobservable inputs. Transfers

between levels, if any, are recognized at the end of each reporting

period.

Fair Values - Recurring

Occidental primarily applies the market approach for recurring

fair value measurements, maximizes its use of observable inputs and

minimizes its use of unobservable inputs. Occidental utilizes the midpoint price between bid and ask prices for valuing the majority of its

assets and liabilities measured and reported at fair value. In addition

to using market data, Occidental makes assumptions in valuing its

assets and liabilities, including assumptions about the risks inherent

in the inputs to the valuation technique. For assets and liabilities

carried at fair value, Occidental measures fair value using the

following methods:

Ø Commodity derivatives – Occidental values exchange-cleared

commodity derivatives using closing prices provided by the

exchange as of the balance sheet date. These derivatives are

classified as Level 1. Over-the-Counter (OTC) bilateral financial

commodity contracts, foreign exchange contracts, options and

physical commodity forward purchase and sale contracts are

generally valued using quotations provided by brokers or

industry-standard models that consider various inputs, including

quoted forward prices for commodities, time value, volatility

factors, credit risk and current market and contractual prices for

the underlying instruments, as well as other relevant economic

measures. Substantially all of these inputs are observable in the

marketplace throughout the full term of the instrument, and can

be derived from observable data or are supported by observable

prices at which transactions are executed in the marketplace.

Occidental generally classifies these measurements as Level 2.

Ø Embedded commodity derivatives – Occidental values embedded

commodity derivatives based on a market approach that considers

various assumptions, including quoted forward commodity prices

and market yield curves. The assumptions used include inputs

that are observable and unobservable in the marketplace, and

the fair value is designated as Level 3 within the valuation

hierarchy.

Occidental generally uses an income approach to measure fair

value when there is not a market-observable price for an identical or

similar asset or liability. This approach utilizes management's

judgments regarding expectations of projected cash flows, and

discounts those cash flows using a risk-adjusted discount rate.

Environmental Liabilities and Expenditures

Environmental expenditures that relate to current operations are

expensed or capitalized as appropriate. Occidental records

environmental reserves for estimated remediation costs that relate to

existing conditions from past operations when environmental

remediation efforts are probable and the costs can be reasonably

estimated. In determining the reserves and the range of reasonably

possible additional losses, Occidental refers to currently available

information, including relevant past experience, remedial objectives,

available technologies, applicable laws and regulations and costsharing arrangements. Occidental bases environmental reserves on

management’s estimate of the most likely cost to be incurred, using

the most cost-effective technology reasonably expected to achieve the

remedial objective. Occidental periodically reviews reserves and

adjusts them as new information becomes available. Occidental

records environmental reserves on a discounted basis when it deems

the aggregate amount and timing of cash payments to be reliably

determinable at the time the reserves are established. The reserve

methodology with respect to discounting for a specific site is not

modified once it is established. The amount of discounted

environmental reserves is insignificant. Occidental generally records

reimbursements or recoveries of environmental remediation costs in

income when received, or when receipt of recovery is highly probable.

As of December 31, 2012, 2011 and 2010, Occidental did not have

any accruals for reimbursements or recoveries.

Many factors could affect Occidental’s future remediation costs

and result in adjustments to its environmental reserves and range of

reasonably possible additional losses. The most significant are: (1) cost

estimates for remedial activities may be inaccurate; (2) the length of

time, type or amount of remediation necessary to achieve the remedial

objective may change due to factors such as site conditions, the ability

to identify and control contaminant sources or the discovery of

additional contamination; (3) a regulatory agency may ultimately

reject or modify Occidental’s proposed remedial plan; (4) improved or

alternative remediation technologies may change remediation costs;

(5) laws and regulations may change remediation requirements or

affect cost sharing or allocation of liability; and (6) changes in

allocation or cost-sharing arrangements.

33
Certain sites involve multiple parties with various cost-sharing

arrangements, which fall into the following three categories: (1)

environmental proceedings that result in a negotiated or prescribed

allocation of remediation costs among Occidental and other alleged

potentially responsible parties; (2) oil and gas ventures in which each

participant pays its proportionate share of remediation costs reflecting

its working interest; or (3) contractual arrangements, typically relating

to purchases and sales of properties, in which the parties to the

transaction agree to methods of allocating remediation costs. In these

circumstances, Occidental evaluates the financial viability of other

parties with whom it is alleged to be jointly liable, the degree of their

commitment to participate and the consequences to Occidental of their

failure to participate when estimating Occidental's ultimate share of

liability. Occidental records reserves at its expected net cost of

remedial activities and, based on these factors, believes that it will not

be required to assume a share of liability of such other potentially

responsible parties in an amount materially above amounts reserved.

In addition to the costs of investigations and cleanup measures,

which often take in excess of 10 years at NPL sites, Occidental’s

reserves include management’s estimates of the costs to operate and

maintain remedial systems. If remedial systems are modified over time

in response to significant changes in site-specific data, laws,

regulations, technologies or engineering estimates, Occidental

reviews and adjusts its reserves accordingly.

If Occidental were to adjust the environmental reserve balance

based on the factors described above, the amount of the increase or

decrease would be recognized in earnings. For example, if the

reserve balance were reduced by 10 percent, Occidental would record

a pre-tax gain of $34 million. If the reserve balance were increased by

10 percent, Occidental would record an additional remediation

expense of $34 million.

Other Loss Contingencies

Occidental is involved with numerous lawsuits, claims,

proceedings and audits in the normal course of its operations.

Occidental records a loss contingency for these matters when it is

probable that an asset has been impaired or a liability has been

incurred and the amount of the loss can be reasonably estimated. In

addition, Occidental discloses, in aggregate, its exposure to loss in

excess of the amount recorded on the balance sheet for these matters

if it is reasonably possible that an additional material loss may be

incurred. Occidental reviews its loss contingencies on an ongoing

basis.

Loss contingencies are based on judgments made by

management with respect to the likely outcome of these matters and

are adjusted as appropriate. Management’s judgments could change

based on new information, changes in, or interpretations of, laws or

regulations, changes in management’s plans or intentions, opinions

regarding the outcome of legal proceedings, or other factors. See

"Lawsuits, Claims and Other Contingencies" for additional

information.

SIGNIFICANT ACCOUNTING AND DISCLOSURE

CHANGES

Listed below are significant recently adopted accounting and

disclosure changes.

Fair Value Measurements

Beginning in the quarter ended March 31, 2012, Occidental

enhanced its fair value measurement application and disclosures as a

result of adopting new requirements issued by the Financial

Accounting Standards Board in May 2011. The new rules include

revisions to the standards for the use of fair value measurements and

additional disclosures for: (i) all transfers between Level 1 and Level 2

of the fair value hierarchy; (ii) Level 3 measurements; and (iii)

hierarchy classifications used for assets and liabilities whose fair

value is disclosed only in the footnotes. The new rules did not have a

material impact on Occidental.

DERIVATIVE ACTIVITIES AND MARKET RISK

Commodity Price Risk

General

Occidental’s results are sensitive to fluctuations in oil, NGL and

natural gas prices. Price changes at current global prices and levels of

production affect Occidental’s pre-tax annual income by approximately

$150 million for a $1 per barrel change in oil prices and $30 million for

a $1 per barrel change in NGL prices. If domestic natural gas prices

varied by $0.50 per Mcf, it would have an estimated annual effect on

Occidental's pre-tax income of approximately $115 million. These

price-change sensitivities include the impact of PSC and similar

contract volume changes on income. If production levels change in

the future, the sensitivity of Occidental’s results to oil and gas prices

also will change. The marketing and trading results are also sensitive

to price changes of oil, gas and, to a lesser degree, other commodities.

These sensitivities are additionally dependent on marketing and

trading volumes and cannot be predicted reliably.

Occidental’s results are also sensitive to fluctuations in chemical

prices. A variation in chlorine and caustic soda prices of $10 per ton

would have a pre-tax annual effect on income of approximately $10

million and $30 million, respectively. A variation in PVC prices of

$0.01 per lb. would have a pre-tax annual effect on income of

approximately $25 million. Historically, over time, product price

changes have tracked raw material and feedstock product price

changes, somewhat mitigating the effect of price changes on margins.

According to Chemical Market Associates, Inc., December 2012

average contract prices were: chlorine—$255 per ton; caustic soda

—$635 per ton; and PVC—$0.56 per lb.

Occidental uses derivative instruments, including a combination

of short-term futures, forwards, options and swaps, to establish, as of

the date of production, the price it receives and to improve realized

prices for oil and gas. Occidental only occasionally hedges its oil and

gas production and, when it does so, the volumes are usually

insignificant. Additionally, Occidental’s Phibro trading unit engages

in trading activities using derivatives for the

34
purpose of generating profits mainly from market price changes of

commodities. 

Risk Management

Occidental conducts its risk management activities for marketing

and trading activities under the controls and governance of its risk

control policy. The controls under this policy are implemented and

enforced by certain members of management embedded in the

marketing and trading operations in order to manage risk by providing

an independent and separate evaluation and check. These members

of management report to the Corporate Vice President and Treasurer.

The President and Chief Executive Officer and risk committees

comprising members of Occidental's senior corporate management

also oversee these controls. Controls for these activities include limits

on value at risk, limits on credit, limits on total notional trade value,

segregation of duties, delegation of authority, daily price verifications,

daily reporting to senior management of positions together with

various risk measures and a number of other policy and procedural

controls. Additionally, these operations maintain highly liquid

positions, as a result of which the market risk typically can be

neutralized on short notice.

Fair Value of Marketing and Trading Derivative Contracts

Occidental's marketing and trading derivative contracts are

carried at fair value and result from third-party marketing and trading

activities, sales of its production and activities to generate profits

mainly from price changes in the commodities markets.

The following table shows the fair value of Occidental's

derivatives (excluding collateral), segregated by maturity periods and

by methodology of fair value estimation:

Maturity Periods

Source of Fair Value

Assets/(liabilities)

(in millions) 2013

2014 and

2015

2016 and

2017

2018

and

thereafter Total

Prices actively quoted $ 9 $ (1) $ — $ — $ 8

Prices provided by other

external sources (60) (27) 1 — (86)

Total $ (51) $ (28) $ 1 $ — $ (78)

Note: Includes cash-flow hedges further discussed below.

Cash-Flow Hedges

Occidental entered into financial swap agreements in November

2012 for the sale of a portion of its natural gas production in California.

These swap agreements hedge 50 million cubic feet of natural gas per

day beginning in January 2013 through March 2014 and qualify as

cash-flow hedges. The weighted-average strike price of these swaps is

$4.30.

Through March 31, 2012, Occidental held financial swap

agreements related to the sale of 50 million cubic feet per day of its

existing natural gas production from the Rocky Mountain region of the

United States that qualified as cash-flow hedges at a weightedaverage strike price of $6.07.

Through 2011, Occidental held a series of collar agreements for

12,000 barrels of oil per day of its domestic production that qualified as

cash-flow hedges at a

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

Occidental’s marketing and trading operations store natural gas

purchased from third parties at Occidental’s North American leased

storage facilities. Derivative instruments are used to fix margins on

the future sales of the stored volumes through March 31, 2013. As of

December 31, 2012 and 2011, Occidental had approximately 20

billion cubic feet and 25 billion cubic feet of natural gas held in

storage, respectively. As of December 31, 2012 and 2011, Occidental

had cash-flow hedges for the forecast sale, to be settled by physical

delivery, of approximately 20 billion cubic feet and 35 billion cubic feet

of this stored natural gas, respectively.

As of December 31, 2012, the total fair value of cash-flow hedges,

which was a net asset of $9 million, was included in the total fair

value table in "Fair Value of Marketing and Trading Derivative

Contracts" above.

Quantitative Information

Occidental uses value at risk to estimate the potential effects of

changes in fair values of commodity-based and foreign currency

derivatives and commodity contracts used in marketing and trading

activities. This method determines the maximum potential negative

short-term change in fair value with at least a 95-percent level of

confidence. Additionally, Occidental uses trading limits, including,

among others, limits on total notional trade value, and maintains

liquid positions as a result of which market risk typically can be

neutralized on short notice. As a result of these controls, Occidental

has determined that the market risk of the marketing and trading

activities is not reasonably likely to have a material adverse effect on

it. 

Interest Rate Risk

General

Occidental's exposure to changes in interest rates is not expected

to be material and relates to its variable-rate long-term debt

obligations. As of December 31, 2012, variable-rate debt constituted

approximately 1 percent of Occidental's total debt.

Tabular Presentation of Interest Rate Risk

The table below provides information about Occidental's debt

obligations. Debt amounts represent principal payments by maturity

date.

Year of Maturity

(in millions of

U.S. dollars)

U.S. Dollar

Fixed-Rate Debt

U.S. Dollar

Variable-Rate Debt Grand Total (a)

2013 $ 600 $ — $ 600

2014 — — —

2015 — — —

2016 1,450 — 1,450

2017 1,250 — 1,250

Thereafter 4,286 68 4,354

Total $ 7,586 $ 68 $ 7,654

Weighted-average

interest rate 3.03% 0.13% 3.01%

Fair Value $ 8,164 $ 68 $ 8,232

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

35
Credit Risk

Occidental's credit risk relates primarily to its derivative financial

instruments and trade receivables. Occidental’s contracts are spread

among a large number of counterparties. Creditworthiness is reviewed

before doing business with a new counterparty and on an ongoing

basis, and master netting arrangements are used when appropriate.

Credit exposure for each customer is monitored for outstanding

balances, current activity, and forward mark-to-market exposure.

A substantial portion of Occidental’s derivative transaction volume

is executed through exchange-traded contracts, which are subject to

nominal credit risk as a significant portion of these transactions is

settled on a daily margin basis with select clearinghouses and

brokers. Occidental executes the rest of its derivative transactions in

the OTC market. Occidental is subject to counterparty credit risk to the

extent the counterparty to the derivatives is unable to meet its

settlement commitments. Occidental manages this credit risk by

selecting counterparties that it believes to be financially strong, by

spreading the credit risk among many such counterparties, by

entering into master netting arrangements with the counterparties

and by requiring collateral, as appropriate. Occidental actively

monitors the creditworthiness of each counterparty and records

valuation adjustments to reflect counterparty risk, if necessary.

Certain of Occidental's OTC derivative instruments contain creditrisk-contingent features, primarily tied to credit ratings for Occidental

or its counterparties, which may affect the amount of collateral that

each would need to post. As of December 31, 2012 and 2011,

Occidental had a net liability of $34 million and $58 million,

respectively, which are net of collateral posted of $64 million and $27

million, respectively. Occidental believes that if it had received a onenotch reduction in its credit ratings, it would not have resulted in a

material change in its collateral-posting requirements as of

December 31, 2012 and 2011.

As of December 31, 2012, the substantial majority of the credit

exposures was with investment grade counterparties. Occidental

believes its exposure to credit-related losses at December 31, 2012

was not material and losses associated with credit risk have been

insignificant for all years presented.

Foreign Currency Risk

Occidental’s foreign operations have limited currency risk.

Occidental manages its exposure primarily by balancing monetary

assets and liabilities and limiting cash positions in foreign currencies

to levels necessary for operating purposes. A vast majority of

international oil sales are denominated in United States dollars.

Additionally, all of Occidental’s consolidated foreign oil and gas

subsidiaries have the United States dollar as the functional currency.

As of December 31, 2012, the fair value of foreign currency

derivatives used in the trading operations was immaterial. The effect

of exchange rates on transactions in foreign currencies is included in

periodic income.

SAFE HARBOR DISCUSSION REGARDING OUTLOOK

AND OTHER FORWARD-LOOKING DATA

Portions of this report, including Items 1 and 2 (including the

information appearing under the captions "Legal Proceedings,"

"Business and Properties — Competition and Sales and Marketing")

and Items 7 and 7A (including "Management's Discussion and

Analysis of Financial Condition and Results of Operations," including

the information under the sub captions "Strategy," "Oil and Gas

Segment — Operations, United Arab Emirates," "— Proved

Reserves," "—Business Review" and "— Industry Outlook,"

"Chemical Segment — Business Review, Basic Chemicals,"

"— Industry Outlook," "Midstream, Marketing and Other

Segment — Business Review, Gas Processing Plants and CO2

Fields and Facilities" and "— Business Review, Pipeline

Transportation," "— Industry Outlook," "Segment Results of

Operations — Oil and Gas," "Taxes," "Consolidated Results of

Operations — Selected Expense Items," "Liquidity and Capital

Resources," "Lawsuits, Claims and Other Contingencies,"

"Environmental Liabilities and Expenditures," "Critical Accounting

Policies and Estimates," and "Derivative Activities and Market Risk"),

contain forward-looking statements and involve risks and

uncertainties that could materially affect expected results of

operations, liquidity, cash flows and business prospects. Words such

as "estimate," "project," "predict," "will," "would," "should," "could,"

"may," "might," "anticipate," "plan," "intend," "believe," "expect,"

"aim," "goal," "target," "objective," "likely" or similar expressions that

convey the prospective nature of events or outcomes generally

indicate forward-looking statements. You should not place undue

reliance on these forward-looking statements, which speak only as of

the date of this report. Unless legally required, Occidental does not

undertake any obligation to update any forward-looking statements as

a result of new information, future events or otherwise. Factors that

may cause Occidental’s results of operations and financial position to

differ from expectations include items noted in Item 1A "Risk Factors,"

and elsewhere.

36
ITEM 8 FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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

The management of Occidental Petroleum Corporation and subsidiaries (Occidental) is responsible for establishing and maintaining adequate

internal control over financial reporting. Occidental’s system of internal control over financial reporting is designed to provide reasonable

assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements for external purposes in

accordance with generally accepted accounting principles. Occidental’s internal control over financial reporting includes those policies and

procedures that: (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of

Occidental’s assets; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in

accordance with generally accepted accounting principles, and that Occidental’s receipts and expenditures are being made only in accordance

with authorizations of Occidental’s management and directors; and (iii) provide reasonable assurance regarding prevention or timely detection of

unauthorized acquisition, use or disposition of Occidental’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any

evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that

the degree of compliance with the policies or procedures may deteriorate.

Management has assessed the effectiveness of Occidental’s internal control system as of December 31, 2012, based on the criteria for

effective internal control over financial reporting described in Internal Control — Integrated Framework issued by the Committee of Sponsoring

Organizations of the Treadway Commission (COSO). Based on this assessment, management believes that, as of December 31, 2012,

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

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

37
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM ON CONSOLIDATED FINANCIAL STATEMENTS

To the Board of Directors and Stockholders

Occidental Petroleum Corporation:

We have audited the accompanying consolidated balance sheets of Occidental Petroleum Corporation and subsidiaries as of December 31,

2012 and 2011, and the related consolidated statements of income, comprehensive income, stockholders’ equity and cash flows for each of the

years in the three-year period ended December 31, 2012. In connection with our audits of the consolidated financial statements, we also have

audited the accompanying financial statement schedule. These consolidated financial statements and financial statement schedule are the

responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements and financial

statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those

standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material

misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An

audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall

financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of

Occidental Petroleum Corporation and subsidiaries as of December 31, 2012 and 2011, and the results of their operations and their cash flows for

each of the years in the three-year period ended December 31, 2012, in conformity with U.S. generally accepted accounting principles. Also in our

opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole,

presents fairly, in all material respects, the information set forth therein.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Occidental

Petroleum Corporation and subsidiaries' internal control over financial reporting as of December 31, 2012, based on criteria established in Internal

Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated

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

/s/ KPMG LLP

Los Angeles, California

February 26, 2013

38
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM ON INTERNAL CONTROL OVER FINANCIAL

REPORTING

To the Board of Directors and Stockholders

Occidental Petroleum Corporation:

We have audited Occidental Petroleum Corporation and subsidiaries' internal control over financial reporting as of December 31, 2012, based

on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway

Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its

assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Assessment of

and Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over

financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those

standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial

reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting,

assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on

the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that

our audit provides a reasonable basis for our opinion.

A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of

financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

A company's internal control over financial reporting includes those policies and procedures that: (1) pertain to the maintenance of records that, in

reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance

that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting

principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and

directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or

disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any

evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that

the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Occidental Petroleum Corporation and its subsidiaries maintained, in all material respects, effective internal control over

financial reporting as of December 31, 2012, based on criteria established in Internal Control - Integrated Framework issued by the Committee of

Sponsoring Organizations of the Treadway Commission (COSO).

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated

balance sheets of Occidental Petroleum Corporation and subsidiaries as of December 31, 2012 and 2011, and the related consolidated statements

of income, comprehensive income, stockholders’ equity and cash flows for each of the years in the three-year period ended December 31, 2012,

and our report dated February 26, 2013 expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

Los Angeles, California

February 26, 2013

39
Consolidated Balance Sheets Occidental Petroleum Corporation

and Subsidiaries

In millions

Assets at December 31, 2012 2011

CURRENT ASSETS

Cash and cash equivalents $ 1,592 $ 3,781

Trade receivables, net of reserves of $16 in both 2012 and 2011 4,916 5,395

Inventories 1,344 1,069

Other current assets 1,640 1,297

Total current assets 9,492 11,542

INVESTMENTS IN UNCONSOLIDATED ENTITIES 1,894 2,072

PROPERTY, PLANT AND EQUIPMENT

Oil and gas segment 65,417 56,682

Chemical segment 6,054 5,715

Midstream, marketing and other segment 7,191 5,664

Corporate 1,434 1,310

80,096 69,371

Accumulated depreciation, depletion and amortization (28,032) (23,687)

52,064 45,684

LONG-TERM RECEIVABLES AND OTHER ASSETS, NET 760 746

TOTAL ASSETS $ 64,210 $ 60,044

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

40
Consolidated Balance Sheets Occidental Petroleum Corporation

and Subsidiaries

In millions, except share and per-share amounts

Liabilities and Stockholders’ Equity at December 31, 2012 2011

CURRENT LIABILITIES

Current maturities of long-term debt $ 600 $ —

Accounts payable 4,708 5,304

Accrued liabilities 1,966 2,533

Domestic and foreign income taxes 16 110

Total current liabilities 7,290 7,947

LONG-TERM DEBT, NET 7,023 5,871

DEFERRED CREDITS AND OTHER LIABILITIES

Deferred domestic and foreign income taxes 6,039 4,846

Other 3,810 3,760

9,849 8,606

CONTINGENT LIABILITIES AND COMMITMENTS

STOCKHOLDERS' EQUITY

Common stock, $0.20 par value, authorized 1.1 billion shares, outstanding shares:

2012 — 888,801,436 and 2011 — 886,808,654 178 177

Treasury stock: 2012 — 83,287,187 shares and 2011 — 75,799,573 shares (5,091) (4,502)

Additional paid-in capital 7,441 7,286

Retained earnings 37,990 35,142

Accumulated other comprehensive loss (502) (483)

Total equity attributable to common stock 40,016 37,620

Noncontrolling interest 32 —

Total equity 40,048 37,620

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 64,210 $ 60,044

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

41
Consolidated Statements of Income Occidental Petroleum Corporation

and Subsidiaries

In millions, except per-share amounts

For the years ended December 31, 2012 2011 2010

REVENUES AND OTHER INCOME

Net sales $ 24,172 $ 23,939 $ 19,045

Interest, dividends and other income 81 180 112

24,253 24,119 19,157

COSTS AND OTHER DEDUCTIONS

Cost of sales (excludes depreciation, depletion and amortization of $4,504 in 2012, $3,584 in 2011 and $3,145

in 2010) 7,844 7,385 6,112

Selling, general and administrative and other operating expenses 1,602 1,523 1,396

Depreciation, depletion and amortization 4,511 3,591 3,153

Asset impairments and related items 1,751 — 275

Taxes other than on income 680 605 484

Exploration expense 345 258 262

Interest and debt expense, net 130 298 116

16,863 13,660 11,798

INCOME BEFORE INCOME TAXES AND OTHER ITEMS 7,390 10,459 7,359

Provision for domestic and foreign income taxes (3,118) (4,201) (2,995)

Income from equity investments 363 382 277

INCOME FROM CONTINUING OPERATIONS 4,635 6,640 4,641

Discontinued operations, net (37) 131 (39)

NET INCOME 4,598 6,771 4,602

Less: Net income attributable to noncontrolling interest — — (72)

NET INCOME ATTRIBUTABLE TO COMMON STOCK $ 4,598 $ 6,771 $ 4,530

BASIC EARNINGS PER COMMON SHARE (attributable to common stock)

Income from continuing operations $ 5.72 $ 8.16 $ 5.62

Discontinued operations, net (0.05) 0.16 (0.05)

BASIC EARNINGS PER COMMON SHARE $ 5.67 $ 8.32 $ 5.57

DILUTED EARNINGS PER COMMON SHARE (attributable to common stock)

Income from continuing operations $ 5.71 $ 8.16 $ 5.61

Discontinued operations, net (0.04) 0.16 (0.05)

DILUTED EARNINGS PER COMMON SHARE $ 5.67 $ 8.32 $ 5.56

DIVIDENDS PER COMMON SHARE $ 2.16 $ 1.84 $ 1.47

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

42
Consolidated Statements of Comprehensive Income Occidental Petroleum Corporation

and Subsidiaries

In millions

For the years ended December 31, 2012 2011 2010

Net income attributable to common stock $ 4,598 $ 6,771 $ 4,530

Other comprehensive income (loss) items:

Foreign currency translation (losses) gains (25) (11) 4

Unrealized gains on derivatives (a) 16 14 37

Pension and postretirement gains (losses) (b) 14 (60) (52)

Reclassification to income of realized (gains) losses on derivatives (c) (24) 98 83

Other comprehensive income (loss), net of tax (d) (19) 41 72

Comprehensive income attributable to common stock $ 4,579 $ 6,812 $ 4,602

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

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

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

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

Consolidated Statements of Stockholders' Equity

In millions

Equity Attributable to Common Stock

Common

Stock

Treasury

Stock

Additional

Paid-in

Capital

Retained

Earnings

Accumulated Other

Comprehensive Income

(Loss) Noncontrolling Interest Total Equity

Balance, December 31, 2009 $ 177 $ (4,161) $ 7,127 $ 26,534 $ (596) $ 78 $ 29,159

Net income — — — 4,530 — 72 4,602

Other comprehensive income,

net of tax — — — — 72 — 72

Dividends on common stock — — — (1,196) — — (1,196)

Issuance of common stock and

other, net — — 64 — — — 64

Noncontrolling interest

distributions and other — — — — — (150) (a) (150)

Purchases of treasury stock — (67) — — — — (67)

Balance, December 31, 2010 $ 177 $ (4,228) $ 7,191 $ 29,868 $ (524) $ — $ 32,484

Net income — — — 6,771 — — 6,771

Other comprehensive income,

net of tax — — — — 41 — 41

Dividends on common stock — — — (1,497) — — (1,497)

Issuance of common stock and

other, net — — 95 — — — 95

Purchases of treasury stock — (274) — — — — (274)

Balance, December 31, 2011 $ 177 $ (4,502) $ 7,286 $ 35,142 $ (483) $ — $ 37,620

Net income — — — 4,598 — — 4,598

Other comprehensive loss, net of

tax — — — — (19) — (19)

Dividends on common stock — — — (1,750) — — (1,750)

Issuance of common stock and

other, net 1 — 155 — — — 156

Noncontrolling interest

contributions — — — — — 32 (b) 32

Purchases of treasury stock — (589) — — — — (589)

Balance, December 31, 2012 $ 178 $ (5,091) $ 7,441 $ 37,990 $ (502) $ 32 $ 40,048

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

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

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

43
Consolidated Statements of Cash Flows Occidental Petroleum Corporation

and Subsidiaries

In millions

For the years ended December 31, 2012 2011 2010

CASH FLOW FROM OPERATING ACTIVITIES

Net income $ 4,598 $ 6,771 $ 4,602

Adjustments to reconcile net income to net cash provided by operating activities:

Discontinued operations, net 37 (131) 39

Depreciation, depletion and amortization of assets 4,511 3,591 3,153

Deferred income tax provision 1,128 1,436 406

Other noncash charges to income 195 190 231

Asset impairments and related items 1,751 — 275

Undistributed earnings from equity investments (30) (33) (60)

Dry hole expenses 279 160 139

Changes in operating assets and liabilities:

Decrease (increase) in receivables 472 (360) (929)

(Increase) decrease in inventories (265) (50) (42)

Decrease in other current assets 127 95 210

(Decrease) increase in accounts payable and accrued liabilities (1,086) 657 1,146

Increase (decrease) in current domestic and foreign income taxes 1 (174) 186

Other operating, net (370) 154 —

Operating cash flow from continuing operations 11,348 12,306 9,356

Operating cash flow from discontinued operations, net of taxes (36) (25) 210

Net cash provided by operating activities 11,312 12,281 9,566

CASH FLOW FROM INVESTING ACTIVITIES

Capital expenditures (10,226) (7,518) (3,940)

Payments for purchases of assets and businesses (2,490) (4,909) (4,924)

Sales of assets, net 4 50 20

Other, net 57 (96) (36)

Investing cash flow from continuing operations (12,655) (12,473) (8,880)

Investing cash flow from discontinued operations — 2,570 (415)

Net cash used by investing activities (12,655) (9,903) (9,295)

CASH FLOW FROM FINANCING ACTIVITIES

Proceeds from long-term debt 1,736 2,111 2,584

Payments of long-term debt — (1,523) (311)

Proceeds from issuance of common stock 85 50 10

Purchases of treasury stock (583) (274) (67)

Contributions from (distributions to) noncontrolling interest 32 (121) —

Cash dividends paid (2,128) (1,436) (1,159)

Other, net 12 18 26

Net cash (used) provided by financing activities (846) (1,175) 1,083

(Decrease) increase in cash and cash equivalents (2,189) 1,203 1,354

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

Cash and cash equivalents — end of year $ 1,592 $ 3,781 $ 2,578

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

44
Notes to Consolidated Financial Statements Occidental Petroleum Corporation

and Subsidiaries

NOTE 1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

NATURE OF OPERATIONS

In this report, "Occidental" means Occidental Petroleum Corporation, a Delaware corporation (OPC), or OPC and one or more entities in

which it owns a controlling interest (subsidiaries). Occidental conducts its operations through various subsidiaries and affiliates. Occidental's

principal businesses consist of the oil and gas, chemical and midstream, marketing and other (midstream and marketing) segments. The oil and

gas segment explores for, develops and produces oil and condensate, natural gas liquids (NGLs) and natural gas. The chemical segment

(OxyChem) mainly manufactures and markets basic chemicals and vinyls. The midstream and marketing segment gathers, processes, transports,

stores, purchases and markets oil, condensate, NGLs, natural gas, carbon dioxide (CO 2) and power. It also trades around its assets, including

transportation and storage capacity, and trades oil, NGLs, gas and other commodities. The segment also invests in entities that conduct similar

activities.

PRINCIPLES OF CONSOLIDATION

The consolidated financial statements have been prepared in conformity with United States generally accepted accounting principles (GAAP)

and include the accounts of OPC, its subsidiaries and its undivided interests in oil and gas exploration and production ventures. Occidental

accounts for its share of oil and gas exploration and production ventures, in which it has a direct working interest, by reporting its proportionate

share of assets, liabilities, revenues, costs and cash flows within the relevant lines on the balance sheets, income statements and cash flow

statements.

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

INVESTMENTS IN UNCONSOLIDATED ENTITIES

Occidental’s percentage interest in the underlying net assets of affiliates as to which it exercises significant influence without having a

controlling interest (excluding oil and gas ventures in which Occidental holds an undivided interest) are accounted for under the equity method.

Occidental reviews equity-method investments for impairment whenever events or changes in circumstances indicate that an other-thantemporary decline in value may have occurred. The amount of impairment, if any, is based on quoted market prices, when available, or other

valuation techniques, including discounted cash flows.

REVENUE RECOGNITION

Revenue is recognized from oil and gas production when title has passed to the customer, which occurs when the product is shipped. In

international locations where oil is shipped by tanker, title passes when the tanker is loaded or product is received by the customer, depending on

the shipping terms. This process occasionally causes a difference between actual production in a reporting period and sales volumes that have

been recognized as revenue.

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

programs may provide for payments or credits to be made to customers based on the volume of product purchased over a defined period. Total

customer incentive payments over a given period are estimated and recorded as a reduction to revenue ratably over the contract period. Such

estimates are evaluated and revised as warranted.

Revenue from marketing and trading activities is recognized on net settled transactions upon completion of contract terms and, for physical

deliveries, upon title transfer. For unsettled transactions, contracts are recorded at fair value and changes in fair value are reflected in net sales.

Revenue from all marketing and trading activities is reported on a net basis.

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

RISKS AND UNCERTAINTIES

The process of preparing consolidated financial statements in conformity with GAAP requires Occidental's management to make informed

estimates and judgments regarding certain types of financial statement balances and disclosures. Such estimates primarily relate to unsettled

transactions and events as of the date of the consolidated financial statements and judgments on the materiality of transactions and balances.

Changes in facts and circumstances or discovery of new information relating to such transactions and events may result in revised estimates and

judgments and actual results may differ from estimates upon settlement but generally not by material amounts. Management believes that these

estimates and judgments provide a reasonable basis for the fair presentation of Occidental’s financial statements.

Occidental establishes a valuation allowance against net operating losses and other deferred tax assets to the extent it believes the future

benefit from these assets will not be realized in the statutory carryforward periods. Realization of deferred tax assets, including any net operating

loss carryforwards, is dependent upon Occidental generating sufficient future taxable income and reversal of temporary differences in jurisdictions

where such assets originate.

45
The accompanying consolidated financial statements include assets of approximately $12.3 billion as of December 31, 2012, and net sales of

approximately $8.8 billion for the year ended December 31, 2012, relating to Occidental’s operations in countries outside North America.

Occidental operates some of its oil and gas business in countries that occasionally have experienced political instability, nationalizations, armed

conflict, terrorism, insurgency, civil unrest, security problems, labor unrest, OPEC production restrictions, equipment import restrictions and

sanctions, all of which increase Occidental's risk of loss or delayed or restricted production or may result in other adverse consequences.

Occidental attempts to conduct its affairs so as to mitigate its exposure to such risks and would seek compensation in the event of nationalization.

Because Occidental’s major products are commodities, significant changes in the prices of oil and gas and chemical products may have a

significant impact on Occidental’s results of operations.

Also, see "Property, Plant and Equipment" below.

CASH AND CASH EQUIVALENTS

Cash equivalents are short-term, highly liquid investments that are readily convertible to cash. Cash equivalents were approximately $1.0

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

Investments

Available-for-sale securities are recorded at fair value with any unrealized gains or losses included in accumulated other comprehensive

income/loss (AOCI). Trading securities are recorded at fair value with unrealized and realized gains or losses included in net sales.

Inventories

Materials and supplies are valued at weighted-average cost and are reviewed periodically for obsolescence. Oil, NGL and natural gas

inventories are valued at the lower of cost or market.

For the chemical segment, Occidental's finished goods inventories are valued at the lower of cost or market. For most of its domestic

inventories, other than materials and supplies, the chemical segment uses the last-in, first-out (LIFO) method as it better matches current costs

and current revenue. For other countries, Occidental uses the first-in, first-out method (if the costs of goods are specifically identifiable) or the

average-cost method (if the costs of goods are not specifically identifiable).

PROPERTY, PLANT AND EQUIPMENT

Oil and Gas

The carrying value of Occidental’s property, plant and equipment (PP&E) represents the cost incurred to acquire or develop the asset,

including any asset retirement obligations and capitalized interest, net of accumulated depreciation, depletion and amortization (DD&A) and net of

any impairment charges. For assets acquired, PP&E cost is based on fair values at the acquisition date. Asset retirement obligations and interest

costs incurred in connection with qualifying capital expenditures are capitalized and amortized over the lives of the related assets.

Occidental uses the successful efforts method to account for its oil and gas properties. Under this method, Occidental capitalizes costs of

acquiring properties, costs of drilling successful exploration wells and development costs. The costs of exploratory wells are initially capitalized

pending a determination of whether proved reserves have been found. If proved reserves have been found, the costs of exploratory wells remain

capitalized. Otherwise, Occidental charges the costs of the related wells to expense. In some cases, a determination of proved reserves cannot be

made at the completion of drilling, requiring additional testing and evaluation of the wells. Occidental generally expenses the costs of such

exploratory wells if a determination of proved reserves has not been made within a 12-month period after drilling is complete.

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

In millions 2012 2011 2010

Balance — Beginning of Year $ 182 $ 73 $ 51

Additions to capitalized exploratory well costs pending the determination of proved reserves 400 334 112

Reclassifications to property, plant and equipment based on the determination of proved reserves (407) (204) (73)

Capitalized exploratory well costs charged to expense (77) (21) (17)

Balance — End of Year $ 98 $ 182 $ 73

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

Occidental expenses the costs of injectants used in production.

Occidental determines depreciation and depletion of oil and gas producing properties by the unit-of-production method. It amortizes acquisition

costs over total proved reserves, and capitalized development and successful exploration costs over proved developed reserves.

46
Proved oil and gas reserves (as defined in the Securities and Exchange Commission's Regulation S-X, Rule 4-10(a)) are those quantities of oil

and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from

a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to

the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of

whether deterministic or probabilistic methods are used for the estimation. Occidental has no proved oil and gas reserves for which the

determination of economic producibility is subject to the completion of major additional capital expenditures.

A portion of the carrying value of Occidental’s oil and gas properties is attributable to unproved properties. At December 31, 2012, the net

capitalized costs attributable to unproved properties were $4.8 billion. The unproved amounts are not subject to DD&A until they are classified as

proved properties. As exploration and development work progresses, if reserves on these properties are proved, capitalized costs attributable to the

properties become subject to DD&A. If the exploration and development work were to be unsuccessful, or management's plans changed with

respect to these properties, as a result of economic, operating or contractual conditions, the capitalized costs of the related properties would be

expensed. The timing of any writedowns of these unproved properties, if warranted, depends upon management's plans, the nature, timing and

extent of future exploration and development activities and their results. Occidental believes its current plans and exploration and development

efforts will allow it to realize its unproved property balance.

Additionally, Occidental performs impairment tests with respect to its proved properties generally when prices decline other than temporarily,

reserve estimates change significantly or other significant events occur that may impact its ability to realize the recorded asset amounts.

Impairment tests incorporate a number of assumptions involving expectations of future cash flows, which can change significantly over time.

These assumptions include estimates of future product prices, which Occidental bases on forward price curves and, when applicable, contractual

prices, estimates of oil and gas reserves and estimates of future expected operating and development costs.

Fluctuations in commodity prices and production and development costs could cause management's plans to change with respect to unproved

properties and could cause the carrying values of proved properties to be unrealizable. Such circumstances could result in impairments in the

carrying values of proved or unproved properties or both. Any impairment loss would be calculated as the excess of the asset’s net book value over

its estimated fair value.

Chemical

Occidental’s chemical assets are depreciated using either the unit-of-production or the straight-line method, based upon the estimated useful

lives of the facilities. The estimated useful lives of Occidental’s chemical assets, which range from three years to 50 years, are also used for

impairment tests. The estimated useful lives for the chemical facilities are based on the assumption that Occidental will provide an appropriate

level of annual expenditures to ensure productive capacity is sustained. Such expenditures consist of ongoing routine repairs and maintenance,

as well as planned major maintenance activities (PMMA). Ongoing routine repairs and maintenance expenditures are expensed as incurred.

PMMA costs are capitalized and amortized over the period until the next planned overhaul. Additionally, Occidental incurs capital expenditures

that extend the remaining useful lives of existing assets, increase their capacity or operating efficiency beyond the original specification or add

value through modification for a different use. These capital expenditures are not considered in the initial determination of the useful lives of these

assets at the time they are placed into service. The resulting revision, if any, of the asset’s estimated useful life is measured and accounted for

prospectively.

Without these continued expenditures, the useful lives of these assets could decrease significantly. Other factors that could change the

estimated useful lives of Occidental’s chemical assets include sustained higher or lower product prices, which are particularly affected by both

domestic and foreign competition, demand, feedstock costs, energy prices, environmental regulations and technological changes.

Occidental performs impairment tests on its chemical assets whenever events or changes in circumstances lead to a reduction in the

estimated useful lives or estimated future cash flows that would indicate that the carrying amount may not be recoverable, or when management’s

plans change with respect to those assets. Any impairment loss would be calculated as the excess of the asset’s net book value over its estimated

fair value.

Midstream and Marketing

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

straight-line method.

Occidental performs impairment tests on its midstream and marketing assets whenever events or changes in circumstances lead to a

reduction in the estimated useful lives or estimated future cash flows that would indicate that the carrying amount may not be recoverable, or

when management’s plans change with respect to those assets. Any impairment loss would be calculated as the excess of the asset’s net book

value over its estimated fair value.

FAIR VALUE MEASUREMENTS

Occidental has categorized its assets and liabilities that are measured at fair value in a three-level fair value hierarchy, based on the inputs to

the valuation techniques: Level 1 – using quoted prices in active markets for identical assets or liabilities; Level 2 – using observable inputs other

than quoted prices for identical assets or liabilities; and Level 3 – using unobservable inputs. Transfers between levels, if any, are reported at the

end of each reporting period.

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Fair Values - Recurring

Occidental primarily applies the market approach for recurring fair value measurements, maximizes its use of observable inputs and

minimizes its use of unobservable inputs. Occidental utilizes the mid-point price between bid and ask prices for valuing the majority of its assets

and liabilities measured and reported at fair value. In addition to using market data, Occidental makes assumptions in valuing its assets and

liabilities, including assumptions about the risks inherent in the inputs to the valuation technique. For assets and liabilities carried at fair value,

Occidental measures fair value using the following methods:

Ø Commodity derivatives – Occidental values exchange-cleared commodity derivatives using closing prices provided by the exchange as of the

balance sheet date. These derivatives are classified as Level 1. Over-the-Counter (OTC) bilateral financial commodity contracts, foreign

exchange contracts, options and physical commodity forward purchase and sale contracts are generally valued using quotations provided by

brokers or industry-standard models that consider various inputs, including quoted forward prices for commodities, time value, volatility

factors, credit risk and current market and contractual prices for the underlying instruments, as well as other relevant economic measures.

Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument and can be derived from

observable data or are supported by observable prices at which transactions are executed in the marketplace. Occidental classifies these

measurements as Level 2.

Ø Embedded commodity derivatives – Occidental values embedded commodity derivatives based on a market approach that considers various

assumptions, including quoted forward commodity prices and market yield curves. The assumptions used include inputs that are observable

and unobservable in the marketplace, and the fair value is designated as Level 3 within the valuation hierarchy.

Occidental generally uses an income approach to measure fair value when there is not a market-observable price for an identical or similar

asset or liability. This approach utilizes management's judgments regarding expectations of projected cash flows, and discounts those cash flows

using a risk-adjusted discount rate.

ACCRUED LIABILITIES—CURRENT

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

2011, respectively.

ENVIRONMENTAL LIABILITIES AND EXPENDITURES

Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Occidental records environmental

reserves for estimated remediation costs that relate to existing conditions from past operations when environmental remediation efforts are probable

and the costs can be reasonably estimated. In determining the reserves and the range of reasonably possible additional losses, Occidental refers

to currently available information, including relevant past experience, remedial objectives, available technologies, applicable laws and

regulations and cost-sharing arrangements. Occidental bases environmental reserves on management’s estimate of the most likely cost to be

incurred, using the most cost-effective technology reasonably expected to achieve the remedial objective. Occidental periodically reviews reserves

and adjusts them as new information becomes available. Occidental records environmental reserves on a discounted basis when it deems the

aggregate amount and timing of cash payments to be reliably determinable at the time the reserves are established. The reserve methodology with

respect to discounting for a specific site is not modified once it is established. The amount of discounted environmental reserves is insignificant.

Occidental generally records reimbursements or recoveries of environmental remediation costs in income when received, or when receipt of

recovery is highly probable. As of December 31, 2012, 2011 and 2010, Occidental did not have any accruals for reimbursements or recoveries.

Many factors could affect Occidental’s future remediation costs and result in adjustments to its environmental reserves and range of

reasonably possible additional losses. The most significant are: (1) cost estimates for remedial activities may be inaccurate; (2) the length of time,

type or amount of remediation necessary to achieve the remedial objective may change due to factors such as site conditions, the ability to identify

and control contaminant sources or the discovery of additional contamination; (3) a regulatory agency may ultimately reject or modify Occidental’s

proposed remedial plan; (4) improved or alternative remediation technologies may change remediation costs; (5) laws and regulations may change

remediation requirements or affect cost sharing or allocation of liability; and (6) changes in allocation or cost-sharing arrangements.

Certain sites involve multiple parties with various cost-sharing arrangements, which fall into the following three categories: (1) environmental

proceedings that result in a negotiated or prescribed allocation of remediation costs among Occidental and other alleged potentially responsible

parties; (2) oil and gas ventures in which each participant pays its proportionate share of remediation costs reflecting its working interest; or (3)

contractual arrangements, typically relating to purchases and sales of properties, in which the parties to the transaction agree to methods of

allocating remediation costs. In these circumstances, Occidental evaluates the financial viability of the other parties with whom it is alleged to be

jointly liable, the degree of their commitment to participate and the consequences to Occidental of their failure to participate when estimating

Occidental's ultimate share of liability. Occidental records reserves at its expected net cost of remedial activities and, based on these factors,

believes that it will not be required to assume a share of liability of such other potentially responsible parties in an amount materially above

amounts reserved.

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In addition to the costs of investigations and cleanup measures, which often take in excess of 10 years at Comprehensive Environmental

Response, Compensation, and Liability Act (CERCLA) National Priorities List (NPL) sites, Occidental’s reserves include management’s estimates of

the costs to operate and maintain remedial systems. If remedial systems are modified over time in response to significant changes in site-specific

data, laws, regulations, technologies or engineering estimates, Occidental reviews and adjusts its reserves accordingly.

ASSET RETIREMENT OBLIGATIONS

Occidental recognizes the fair value of asset retirement obligations in the period in which a determination is made that a legal obligation exists

to dismantle an asset and reclaim or remediate the property at the end of its useful life and the cost of the obligation can be reasonably estimated.

The liability amounts are based on future retirement cost estimates and incorporate many assumptions such as time to abandonment,

technological changes, future inflation rates and the risk-adjusted discount rate. When the liability is initially recorded, Occidental capitalizes the

cost by increasing the related PP&E balances. If the estimated future cost of the asset retirement obligation changes, Occidental records an

adjustment to both the asset retirement obligation and PP&E. Over time, the liability is increased and expense is recognized for accretion, and the

capitalized cost is depreciated over the useful life of the asset.

At a certain number of its facilities, Occidental has identified conditional asset retirement obligations that are related mainly to plant

decommissioning. Occidental believes that there is an indeterminate settlement date for these asset retirement obligations because the range of

time over which Occidental may settle these obligations is unknown or cannot be estimated. Therefore, Occidental cannot reasonably estimate the

fair value of these liabilities. Occidental will recognize these conditional asset retirement obligations in the periods in which sufficient information

becomes available to reasonably estimate their fair values.

The following table summarizes the activity of the asset retirement obligation, of which $1,212 million and $1,030 million is included in

deferred credits and other liabilities - other, with the remaining current portion in accrued liabilities at December 31, 2012 and 2011, respectively.

For the years ended December 31, (in millions) 2012 2011

Beginning balance $ 1,089 $ 800

Liabilities incurred – capitalized to PP&E 86 74

Liabilities settled and paid (58) (53)

Accretion expense 61 48

Acquisitions and other – capitalized to PP&E 50 177

Revisions to estimated cash flows – capitalized to PP&E 38 43

Ending balance $ 1,266 $ 1,089

DERIVATIVE INSTRUMENTS

Derivatives are carried at fair value and on a net basis when a legal right of offset exists with the same counterparty. Occidental applies

hedge accounting when transactions meet specified criteria for cash-flow hedge treatment and management elects and documents such treatment.

Otherwise, any fair value gains or losses are recognized in earnings in the current period. For cash-flow hedges, the gain or loss on the effective

portion of the derivative is reported as a component of other comprehensive income (OCI) with an offsetting adjustment to the basis of the item

being hedged. Realized gains or losses from cash-flow hedges, and any ineffective portion, are recorded as a component of net sales in the

consolidated statements of income. Ineffectiveness is primarily created by a basis difference between the hedged item and the hedging instrument

due to location, quality or grade of the physical commodity underlying the hedging instrument. Gains and losses from derivative instruments are

reported net in the consolidated statements of income. There were no fair value hedges as of and during the years ended December 31, 2012,

2011 and 2010.

A hedge is regarded as highly effective such that it qualifies for hedge accounting if, at inception and throughout its life, it is expected that

changes in the fair value or cash flows of the hedged item will be offset by 80 to 125 percent of the changes in the fair value or cash flows,

respectively, of the hedging instrument. In the case of hedging a forecast transaction, the transaction must be probable and must present an

exposure to variations in cash flows that could ultimately affect reported net income or loss. Occidental discontinues hedge accounting when it

determines that a derivative has ceased to be highly effective as a hedge; when the hedged item matures or is sold or repaid; or when a forecast

transaction is no longer deemed probable.

STOCK-BASED INCENTIVE PLANS

Occidental has established several stockholder-approved stock-based incentive plans for certain employees and directors (Plans) that are more

fully described in Note 12. A summary of Occidental’s accounting policy for awards issued under the Plans follows.

For cash- and stock-settled restricted stock units or incentive award shares (RSUs), compensation value is initially measured on the grant date

using the quoted market price of Occidental’s common stock. For total shareholder return incentives (TSRIs), compensation value is initially

measured on the grant date using estimated payout levels derived from

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the Monte Carlo valuation model. Compensation expense for RSUs and TSRIs is recognized on a straight-line basis over the requisite service

periods, which is generally over the awards’ respective vesting or performance periods. Compensation expense for the cash-settled portion of

TSRIs and related dividends is adjusted quarterly for any changes in the number of shares expected to be issued based on the performance

criteria using the Monte Carlo valuation model. In addition, every quarter, compensation expense for the cash-settled portion of RSUs and TSRIs

is adjusted for changes in the value of the underlying stock. All such performance or stock-price-related changes are recognized in periodic

compensation expense. The stock-settled portion of all these awards is expensed using the initially measured compensation value.

EARNINGS PER SHARE

Occidental's instruments containing rights to nonforfeitable dividends granted in stock-based payment transactions are considered

participating securities prior to vesting and, therefore, have been included in the earnings allocations in computing basic and diluted EPS under

the two-class method.

Basic EPS was computed by dividing net income attributable to common stock, net of income allocated to participating securities, by the

weighted-average number of common shares outstanding during each period, net of treasury shares and including vested but unissued shares

and share units. The computation of diluted EPS reflects the additional dilutive effect of stock options and unvested stock awards.

RETIREMENT AND POSTRETIREMENT BENEFIT PLANS

Occidental recognizes the overfunded or underfunded amounts of its defined benefit pension and postretirement plans in its financial

statements using a December 31 measurement date.

Occidental determines its defined benefit pension and postretirement benefit plan obligations based on various assumptions and discount

rates. The discount rate assumptions used are meant to reflect the interest rate at which the obligations could effectively be settled on the

measurement date. Occidental estimates the rate of return on assets with regard to current market factors but within the context of historical

returns. Occidental funds and expenses negotiated pension increases for domestic union employees over the terms of the applicable collective

bargaining agreements.

Pension and postretirement plan assets are measured at fair value. Common stock, preferred stock, publicly registered mutual funds, U.S.

government securities and corporate bonds are valued using quoted market prices in active markets when available. When quoted market prices

are not available, these investments are valued using pricing models with observable inputs from both active and non-active markets. Common

and collective trusts are valued at the fund units' net asset value (NAV) provided by the issuer, which represents the quoted price in a non-active

market. Short-term investment funds are valued at the fund units' NAV provided by the issuer.

SUPPLEMENTAL CASH FLOW INFORMATION

Occidental paid United States federal, state and foreign income taxes for continuing operations of approximately $2.4 billion, $2.9 billion and

$2.4 billion during the years ended December 31, 2012, 2011 and 2010, respectively. Occidental also paid production, property and other taxes of

approximately $694 million, $635 million and $510 million during the years ended December 31, 2012, 2011 and 2010, respectively, substantially

all of which was in the United States. Interest paid totaled approximately $190 million, $315 million and $161 million for the years 2012, 2011 and

2010, respectively. The 2011 interest paid included $154 million of debt extinguishment premiums.

FOREIGN CURRENCY TRANSACTIONS

The functional currency applicable to all of Occidental’s foreign oil and gas operations is the United States dollar since cash flows are

denominated principally in United States dollars. In Occidental's other operations, Occidental's use of non-United States dollar functional

currencies was not material for all years presented. The effect of exchange rates on transactions in foreign currencies is included in periodic

income. Occidental reports the exchange rate differences arising from translating foreign currency denominated balance sheet accounts to the

United States dollar as of the reporting date in other comprehensive income. Exchange-rate gains and losses for continuing operations were not

material for all years presented.

NOTE 2 ACQUISITIONS, DISPOSITIONS AND OTHER TRANSACTIONS

2012

During the year ended December 31, 2012, Occidental paid approximately $2.3 billion for domestic oil and gas properties in the Permian

Basin, Williston Basin, South Texas and California.

In November 2012, Occidental and Magellan Midstream Partners, L.P. (Magellan) formed BridgeTex Pipeline Company, LLC (BridgeTex) and

are proceeding with the construction of the BridgeTex Pipeline, which is expected to begin service in mid-2014. The approximately 450-mile-long

pipeline will be capable of transporting approximately 300,000 barrels per day of crude oil between the Permian region (Colorado City, TX) and the

Gulf Coast refinery markets. The BridgeTex Pipeline project also includes construction of approximately 2.6 million barrels of oil storage in

aggregate.

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Occidental owns a 50% interest in BridgeTex and the remaining 50% interest is owned by Magellan, which also serves as the operator.

BridgeTex was determined to be a variable interest entity because of the difference between Occidental's economic interests and its decisionmaking rights. Occidental is the primary beneficiary and consequently consolidates BridgeTex. At December 31, 2012, BridgeTex held

approximately $50 million of money market mutual funds, classified as cash equivalents, which approximates fair value using Level 1 inputs.

BridgeTex's assets cannot be used for the obligations of, nor do BridgeTex's creditors have recourse to, OPC or its other subsidiaries.

2011

During the year ended December 31, 2011, Occidental acquired producing properties in South Texas for approximately $1.8

billion. Occidental also acquired approximately $2.6 billion of other domestic oil and gas assets, which included properties in California, as well as

the Permian and Williston Basins.

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

Internationally, in the first quarter of 2011, Occidental acquired a 40-percent participating interest in the Al Hosn gas project in Abu Dhabi,

joining with the Abu Dhabi National Oil Company in a 30-year joint venture agreement. The project is operated by Abu Dhabi Gas Development

Company Limited. In May 2011, Occidental paid approximately $500 million for its share of pre-acquisition development expenditures.

In early 2011, Occidental ceased exploration activity and its participation in production operations in Libya due to civil unrest in the country

and United States sanctions. As a result, Occidental wrote off the entire amount of the capitalized and suspended exploration costs incurred to

date, including lease acquisition costs, of approximately $35 million in the first quarter of 2011. The United States government lifted its sanctions

in September 2011 and Occidental resumed its participation in the producing operations at that time.

2010

In December 2010, Occidental acquired oil producing and prospective properties in North Dakota for approximately $1.4 billion in cash. In

2010, Occidental also acquired various domestic oil and gas interests, in operated, producing and non-producing properties in the Permian Basin,

Midcontinent region and California, for approximately $2.8 billion.

In December 2010, Occidental executed an agreement with a subsidiary of China Petrochemical Corporation (Sinopec) to sell its Argentine oil

and gas operations for after-tax proceeds of approximately $2.6 billion. Occidental recorded a pre-tax gain of $225 million when the sale closed in

February 2011. Net revenues and pre-tax income for discontinued operations related to Argentina were $97 million and $2 million, respectively, for

the year ended December 31, 2011. Net revenues and pre-tax losses for such discontinued operations in 2010 were $700 million and $(39)

million, respectively.

In December 2010, Occidental purchased additional noncontrolling interests in the general partner of Plains All-American Pipeline, L.P.

(Plains Pipeline) for approximately $430 million, and now owns 35 percent of the general partner. In December 2010, Occidental also completed its

acquisition of the remaining 50-percent joint venture interest in Elk Hills Power, LLC (EHP), a limited liability company that operates a gas-fired

power-generation plant in California, for approximately $175 million, bringing Occidental’s total ownership to 100 percent. EHP is now

consolidated in Occidental's balance sheet.

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

Zubair Field in Iraq.

NOTE 3 ACCOUNTING AND DISCLOSURE CHANGES

RECENTLY ADOPTED ACCOUNTING AND DISCLOSURE CHANGES

Fair Value Measurements

Beginning in the quarter ended March 31, 2012, Occidental enhanced its fair value measurement application and disclosures as a result of

adopting new requirements issued by the Financial Accounting Standards Board in May 2011. The new rules include revisions to the standards

for the use of fair value measurements and additional disclosures for: (i) all transfers between Level 1 and Level 2 of the fair value hierarchy; (ii)

Level 3 measurements; and (iii) hierarchy classifications used for assets and liabilities whose fair value is disclosed only in the footnotes. The new

rules did not have a material impact on Occidental.

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NOTE 4 INVENTORIES

Net carrying values of inventories valued under the LIFO method were approximately $185 million and $176 million at December 31, 2012

and 2011, respectively. Inventories consisted of the following:

Balance at December 31, (in millions) 2012 2011

Raw materials $ 70 $ 69

Materials and supplies 612 443

Finished goods 763 655

1,445 1,167

LIFO reserve (101) (98)

Total $ 1,344 $ 1,069

NOTE 5 LONG-TERM DEBT

Long-term debt consisted of the following:

Balance at December 31, (in millions) 2012 2011

4.10% senior notes due 2021 $ 1,300 $ 1,300

1.75% senior notes due 2017 1,250 1,250

2.70% senior notes due 2023 1,250 —

3.125% senior notes due 2022 900 900

4.125% senior notes due 2016 750 750

2.5% senior notes due 2016 700 700

1.45% senior notes due 2013 600 600

1.50% senior notes due 2018 500 —

8.45% senior notes due 2029 116 116

9.25% senior debentures due 2019 116 116

7.2% senior debentures due 2028 82 82

Variable rate bonds due 2030 (0.13% and 0.11% as of December 31, 2012 and 2011, respectively) 68 68

8.75% medium-term notes due 2023 22 22

7,654 5,904

Less:

Unamortized discount, net (31) (33)

Current maturities (600) —

Total $ 7,023 $ 5,871

Occidental has a bank credit facility (Credit Facility) with a $2.0 billion commitment expiring in 2016. No amounts have been drawn under

this Credit Facility. Up to $1.0 billion of the Credit Facility is available in the form of letters of credit. Borrowings under the Credit Facility bear

interest at various benchmark rates, including LIBOR, plus a margin based on Occidental's senior debt ratings. Additionally, Occidental paid

average annual facility fees of 0.08 percent in 2012 on the total commitment amounts of the Credit Facility.

The Credit Facility provides for the termination of loan commitments and requires immediate repayment of any outstanding amounts if certain

events of default occur. The Credit Facility and other debt agreements do not contain material adverse change clauses or debt ratings triggers that

could restrict Occidental's ability to borrow or that would permit lenders to terminate their commitments or accelerate debt.

As of December 31, 2012, under the most restrictive covenants of its financing agreements, Occidental had substantial capacity for additional

unsecured borrowings, the payment of cash dividends and other distributions on, or acquisitions of, Occidental stock.

In June 2012, Occidental issued $1.75 billion of debt which comprised $1.25 billion of 2.70-percent senior unsecured notes due 2023 and

$500 million of 1.50-percent senior unsecured notes due 2018. Occidental received net proceeds of approximately $1.74 billion. Interest on the

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

In August 2011, Occidental issued $2.15 billion of debt, which comprised $1.25 billion of 1.75-percent senior unsecured notes due 2017 and

$900 million of 3.125-percent senior unsecured notes due 2022. Occidental received net proceeds of approximately $2.1 billion. Interest on the

notes is payable semi-annually in arrears in February and August for each series of notes.

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In March 2011, Occidental redeemed all $1.0 billion of its outstanding 7-percent senior notes due 2013 and all $368 million of its outstanding

6.75-percent senior notes due 2012. Occidental recorded a $163 million pre-tax charge related to this redemption in the first quarter of 2011.

In December 2010, Occidental issued $2.6 billion of debt, which comprised $600 million of 1.45-percent senior unsecured notes due 2013,

$700 million of 2.50-percent senior unsecured notes due 2016 and $1.3 billion of 4.10-percent senior unsecured notes due 2021. Occidental

received net proceeds of approximately $2.6 billion. Interest on the notes is payable semi-annually in arrears in June and December of each year

for the 1.45-percent notes and February and August of each year for the other notes.

Occidental has provided guarantees on Dolphin Energy's debt, which are limited to certain political and other events. At December 31, 2012

and 2011, Occidental’s total guarantees were not material and a substantial majority of the amounts consisted of limited recourse guarantees on

approximately $370 million and $300 million, respectively, of Dolphin’s debt, of which the fair value was immaterial.

At December 31, 2012, principal payments on long-term debt aggregated $7.6 billion, of which $0.6 billion is due in 2013, $0.0 billion in

2014, $0.0 billion in 2015, $1.4 billion in 2016, $1.2 billion in 2017 and $4.4 billion in 2018 and thereafter.

Occidental estimates the fair value of fixed-rate debt based on the quoted market prices for those instruments or on quoted market yields for

similarly rated debt instruments, taking into account such instruments' maturities. The estimated fair values of Occidental’s debt at December 31,

2012 and 2011, which were classified as Level 1, were approximately $8.2 billion and $6.4 billion, respectively, compared to carrying values of

approximately $7.6 billion and $5.9 billion, respectively. Occidental's exposure to changes in interest rates relates primarily to its variable-rate,

long-term debt obligations, and is not material. As of December 31, 2012 and 2011, variable-rate debt constituted approximately 1 percent of

Occidental's total debt.

NOTE 6 LEASE COMMITMENTS

Operating lease agreements include leases for transportation equipment, power plants, machinery, terminals, storage facilities, land and

office space. Occidental’s operating lease agreements frequently include renewal or purchase options and require it to pay for utilities, taxes,

insurance and maintenance expense. At December 31, 2012, future net minimum lease payments for noncancelable operating leases (excluding

oil and gas and other mineral leases, utilities, taxes, insurance and maintenance expense) were the following:

In millions Amount (a)

2013 $ 158

2014 105

2015 106

2016 88

2017 59

Thereafter 460

Total minimum lease payments $ 976

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

Rental expense for operating leases, net of sublease rental income for continuing operations, was $176 million in 2012, $179 million in 2011

and $170 million in 2010. Rental expense was net of sublease income of $4 million each in 2012, 2011 and 2010.

NOTE 7 DERIVATIVES

Objective & Strategy

Occidental uses a variety of derivative instruments, including cash-flow hedges and derivative instruments not designated as hedging

instruments, to establish, as of the date of production, the price it receives and to improve realized prices for oil and gas. Occidental only

occasionally hedges its oil and gas production and, when it does, the volumes are usually insignificant. Additionally, Occidental’s Phibro trading

unit engages in trading activities using derivatives for the purpose of generating profits mainly from market price changes of commodities.

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

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Cash-Flow Hedges

Occidental entered into financial swap agreements in November 2012 for the sale of a portion of its natural gas production in California. These

swap agreements hedge 50 million cubic feet of natural gas per day beginning in January 2013 through March 2014 and qualify as cash-flow

hedges. The weighted-average strike price of these swaps was $4.30.

Through March 31, 2012, Occidental held financial swap agreements related to the sale of 50 million cubic feet per day of its existing natural

gas production from the Rocky Mountain region of the United States that qualified as cash-flow hedges at a weighted-average strike price of $6.07.

Through December 31, 2011, Occidental held a series of collar agreements for 12,000 barrels of oil per day of its domestic production that

qualified as cash-flow hedges at a weighted-average strike price that ranged from $32.92 to $46.35.

Occidental’s marketing and trading operations store natural gas purchased from third parties at Occidental’s North American leased storage

facilities. Derivative instruments are used to fix margins on the future sales of the stored volumes through March 31, 2013. As of December 31,

2012 and 2011, Occidental had approximately 20 billion cubic feet and 25 billion cubic feet of natural gas held in storage, respectively. As of

December 31, 2012 and 2011, Occidental had cash-flow hedges for the forecast sale, to be settled by physical delivery, of approximately 20 billion

cubic feet and 35 billion cubic feet of this stored natural gas, respectively.

The following table presents the pre-tax and after-tax gains and losses recognized in, and reclassified to income from, AOCI, for derivative

instruments classified as cash-flow hedges for the years ended December 31, 2012 and 2011 (in millions):

After-tax Pre-Tax

2012 2011 2012 2011

Beginning Balance — AOCI $ 1 $ (111)

Unrealized gains recognized in AOCI 16 14 $ 25 $ 20

(Gains) losses reclassified to income (24) 98 $ (38) $ 154

Ending Balance — AOCI $ (7) $ 1

Occidental expects that during the next twelve months an insignificant amount of net after-tax derivative losses included in AOCI based on

their valuation as of December 31, 2012, will be reclassified into income. The gains and losses reclassified to income were recognized in net sales,

and the amount of the ineffective portion of cash-flow hedges was immaterial for the years ended December 31, 2012 and 2011.

Derivatives Not Designated as Hedging Instruments

The following table summarizes Occidental's net volumes resulting from outstanding commodity derivatives contracts not designated as

hedging instruments, including both financial and physical derivative contracts as of December 31, 2012 and 2011:

Net Outstanding Position

Long / (Short)

Commodity 2012 2011

Oil (million barrels) (17) (9)

Natural gas (billion cubic feet) (217) (242)

Precious metals (million troy ounces) 1 3

In addition, Occidental typically has certain other commodity trading contracts, such as agricultural products, power and other metals, as well

as foreign exchange contracts. These contracts were not material to Occidental as of December 31, 2012 and 2011.

Occidental fulfills its short positions through its own production or by third-party purchase contracts. Subsequent to December 31, 2012,

Occidental entered into purchase contracts for a substantial portion of the outstanding positions at year-end and has sufficient production capacity

and the ability to enter into additional purchase contracts to satisfy the remaining positions.

Approximately $49 million and $94 million of net gains from derivatives not designated as hedging instruments were recognized in net sales

for the years ended December 31, 2012 and 2011, respectively.

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Fair Value of Derivatives

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

December 31, 2012

Asset Derivatives

Balance Sheet Location Fair Value

Liability Derivatives

Balance Sheet Location Fair Value

Cash-flow hedges (a)

Commodity contracts Other current assets $ 11 Accrued liabilities $ 1

Long-term receivables and other assets, net — Deferred credits and other liabilities 1

$ 11 $ 2

Derivatives not designated as hedging

instruments (a)

Commodity contracts Other current assets $ 386 Accrued liabilities $ 479

Long-term receivables and other assets, net 22 Deferred credits and other liabilities 16

408 495

Total gross fair value 419 497

Less: counterparty netting and cash

collateral (b) (301) (371)

Total net fair value of derivatives $ 118 $ 126

December 31, 2011

Asset Derivatives

Balance Sheet Location Fair Value

Liability Derivatives

Balance Sheet Location Fair Value

Cash-flow hedges (a)

Commodity contracts Other current assets $ 41 Accrued liabilities $ 5

Long-term receivables and other assets, net 3 Deferred credits and other liabilities —

$ 44 $ 5

Derivatives not designated as hedging

instruments (a)

Commodity contracts Other current assets $ 835 Accrued liabilities $ 887

Long-term receivables and other assets, net 71 Deferred credits and other liabilities 71

906 958

Total gross fair value 950 963

Less: counterparty netting and cash

collateral (c) (758) (782)

Total net fair value of derivatives $ 192 $ 181

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

sheet.

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

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

See Note 15 for fair value measurement disclosures on derivatives.

5 5
Credit Risk

A substantial portion of Occidental’s derivative transaction volume is executed through exchange-traded contracts, which are subject to

nominal credit risk as a significant portion of these transactions is settled on a daily margin basis with select clearinghouses and brokers. Collateral

of $116 million and $173 million deposited by Occidental for such contracts , which has not been reflected in the derivative fair value tables, is

included in the other current assets balance as of December 31, 2012 and 2011, respectively.

Occidental executes the rest of its derivative transactions in the OTC market. Occidental is subject to counterparty credit risk to the extent the

counterparty to the derivatives is unable to meet its settlement commitments. Occidental manages this credit risk by selecting counterparties that it

believes to be financially strong, by spreading the credit risk among many such counterparties, by entering into master netting arrangements

with the counterparties and by requiring collateral, as appropriate. Occidental actively monitors the creditworthiness of each counterparty and

records valuation adjustments to reflect counterparty risk, if necessary.

Certain of Occidental's OTC derivative instruments contain credit-risk-contingent features, primarily tied to credit ratings for Occidental or its

counterparties, which may affect the amount of collateral that each would need to post. As of December 31, 2012 and 2011, Occidental had a net

liability of $34 million and $58 million, respectively, which are net of collateral posted of $64 million and $27 million, respectively. Occidental

believes that if it had received a one-notch reduction in its credit ratings, it would not have resulted in a material change in its collateral-posting

requirements as of December 31, 2012 and 2011.

Foreign Currency Risk

Occidental’s foreign operations have limited currency risk. Occidental manages its exposure primarily by balancing monetary assets and

liabilities and limiting cash positions in foreign currencies to levels necessary for operating purposes. A vast majority of international oil sales are

denominated in United States dollars. Additionally, all of Occidental’s consolidated foreign oil and gas subsidiaries have the United States dollar as

the functional currency.

NOTE 8 ENVIRONMENTAL LIABILITIES AND EXPENDITURES

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

environmental quality. 

ENVIRONMENTAL REMEDIATION

The laws that require or address environmental remediation, including CERCLA and similar federal, state, local and foreign laws, may apply

retroactively and regardless of fault, the legality of the original activities or the current ownership or control of sites. OPC or certain of its

subsidiaries participate in or actively monitor a range of remedial activities and government or private proceedings under these laws with respect

to alleged past practices at operating, closed and third-party sites. Remedial activities may include one or more of the following: investigation

involving sampling, modeling, risk assessment or monitoring; cleanup measures including removal, treatment or disposal; or operation and

maintenance of remedial systems. The environmental proceedings seek funding or performance of remediation and, in some cases, compensation

for alleged property damage, punitive damages, civil penalties, injunctive relief and government oversight costs.

As of December 31, 2012, Occidental participated in or monitored remedial activities or proceedings at 161 sites. The following table presents

Occidental’s environmental remediation reserves as of December 31, 2012, 2011 and 2010, the current portion of which is included in accrued

liabilities ($80 million in 2012, $79 million in 2011 and $79 million in 2010) and the remainder in deferred credits and other liabilities — other

($264 million in 2012, $281 million in 2011 and $287 million in 2010). The reserves are grouped as environmental remediation sites listed or

proposed for listing by the U.S. Environmental Protection Agency on the CERCLA National Priorities List (NPL sites) and three categories of nonNPL sites — third-party sites, Occidental-operated sites and closed or non-operated Occidental sites.

$ amounts in millions 2012 2011 2010

Number of

Sites

Reserve

Balance

Number of

Sites

Reserve

Balance

Number of

Sites

Reserve

Balance

NPL sites 35 $ 54 36 $ 63 38 $ 56

Third-party sites 75 84 73 88 83 91

Occidental-operated sites 22 123 22 120 20 122

Closed or non-operated Occidental sites 29 83 29 89 29 97

Total 161 $ 344 160 $ 360 170 $ 366

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

the sites had reserves from $0 to $1 million each.

As of December 31, 2012, two landfills in western New York owned by Occidental accounted for 73 percent of its reserves associated with NPL

sites. In connection with a 1986 acquisition, Maxus Energy Corporation has retained the liability and indemnified Occidental for 14 of the

remaining NPL sites.

5 6
As of December 31, 2012, Maxus has also retained the liability and indemnified Occidental for 8 of the 75 third-party sites. Two of the

remaining 67 third-party sites — a former copper mining and smelting operation in Tennessee and a containment and removal project in

Tennessee — accounted for 43 percent of Occidental’s reserves associated with these sites.

Five sites — chemical plants in Kansas, Louisiana, Texas and New York and a group of oil and gas properties in the southwestern United

States — accounted for 70 percent of the reserves associated with the Occidental-operated sites.

Three other sites — former chemical plants in Tennessee and Delaware and a closed coal mine in Pennsylvania — accounted for 55 percent

of the reserves associated with closed or non-operated Occidental sites.

Environmental reserves vary over time depending on factors such as acquisitions or dispositions, identification of additional sites and remedy

selection and implementation. The following table presents environmental reserve activity for the past three years:

In millions 2012 2011 2010

Balance — Beginning of Year $ 360 $ 366 $ 403

Remediation expenses and interest accretion 56 53 26

Changes from acquisitions/dispositions — 14 3

Payments (72) (73) (66)

Balance — End of Year $ 344 $ 360 $ 366

Based on current estimates, Occidental expects to expend funds corresponding to approximately half of the current environmental reserves at

the sites described above over the next four years and the balance at these sites over the subsequent 10 or more years. Occidental believes its

range of reasonably possible additional losses beyond those liabilities recorded for environmental remediation at these sites could be up to $375

million.

ENVIRONMENTAL COSTS

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

December 31:

In millions 2012 2011 2010

Operating Expenses

Oil and Gas $ 160 $ 158 $ 108

Chemical 70 68 72

Midstream and Marketing 20 21 13

$ 250 $ 247 $ 193

Capital Expenditures

Oil and Gas $ 122 $ 110 $ 72

Chemical 18 15 19

Midstream and Marketing 12 15 13

$ 152 $ 140 $ 104

Remediation Expenses

Corporate $ 56 $ 52 $ 25

Operating expenses are incurred on a continual basis. Capital expenditures relate to longer-lived improvements in currently operating

properties. Remediation expenses relate to existing conditions from past operations.

NOTE 9 LAWSUITS, CLAIMS, COMMITMENTS AND CONTINGENCIES

OPC or certain of its subsidiaries are involved, in the normal course of business, in lawsuits, claims and other legal proceedings that seek,

among other things, compensation for alleged personal injury, breach of contract, property damage or other losses, punitive damages, civil

penalties, or injunctive or declaratory relief. OPC or certain of its subsidiaries also are involved in proceedings under CERCLA and similar federal,

state, local and foreign environmental laws. These environmental proceedings seek funding or performance of remediation and, in some cases,

compensation for alleged property damage, punitive damages, civil penalties and injunctive relief. Usually OPC or such subsidiaries are among

many companies in these environmental proceedings and have to date been successful in sharing response costs with other financially sound

companies. Further, some lawsuits, claims and legal proceedings involve acquired assets with respect to which third-parties retain liability or

indemnify Occidental for conditions that existed prior to purchase.

Occidental accrues reserves for currently outstanding lawsuits, claims and proceedings when it is probable that a liability has been incurred

and the liability can be reasonably estimated. Occidental has disclosed its reserve balances for environmental matters. Reserve balances for other

matters as of December 31, 2012 and 2011, were not material to

57
Occidental's consolidated balance sheets. Occidental also evaluates the amount of reasonably possible losses that it could incur as a result of the

matters mentioned above. Occidental has disclosed its range of reasonably possible additional losses for sites where it is a participant in

environmental remediation. Occidental believes that other reasonably possible losses that it could incur in excess of reserves accrued on the

balance sheet would not be material to its consolidated financial position or results of operations.

During the course of its operations, Occidental is subject to audit by tax authorities for varying periods in various federal, state, local and

foreign tax jurisdictions. Although taxable years through 2009 for United States federal income tax purposes have been audited by the United

States Internal Revenue Service (IRS) pursuant to its Compliance Assurance Program, subsequent taxable years are currently under review.

Additionally, in December 2012, Occidental filed United States federal refund claims for tax years 2008 and 2009 which are subject to IRS review.

Taxable years from 2000 through the current year remain subject to examination by foreign and state government tax authorities in certain

jurisdictions. In certain of these jurisdictions, tax authorities are in various stages of auditing Occidental’s income taxes. During the course of tax

audits, disputes have arisen and other disputes may arise as to facts and matters of law. Occidental believes that the resolution of outstanding tax

matters would not have a material adverse effect on its consolidated financial position or results of operations.

OPC, its subsidiaries or both have entered into agreements providing for future payments to secure terminal and pipeline capacity, drilling

rigs and services, electrical power, steam and certain chemical raw materials. Occidental has certain other commitments under contracts,

guarantees and joint ventures, including purchase commitments for goods and services at market-related prices and certain other contingent

liabilities. At December 31, 2012, total purchase obligations were $8.7 billion, which included approximately $2.7 billion, $1.4 billion, $700

million, $500 million and $400 million that will be paid in 2013, 2014, 2015, 2016 and 2017, respectively. Included in the purchase obligations

are commitments for major fixed and determinable capital expenditures during 2013 and thereafter, which were approximately $2.2 billion.

OPC, its subsidiaries or both have indemnified various parties against specified liabilities those parties might incur in the future in connection

with purchases and other transactions that they have entered into with Occidental. These indemnities usually are contingent upon the other

party incurring liabilities that reach specified thresholds. As of December 31, 2012, Occidental is not aware of circumstances that it believes would

reasonably be expected to lead to indemnity claims that would result in payments materially in excess of reserves.

NOTE 10 DOMESTIC AND FOREIGN INCOME TAXES

The domestic and foreign components of income from continuing operations before domestic and foreign income taxes and net of noncontrolling

interest amounts were as follows:

For the years ended December 31, (in millions) Domestic Foreign Total

2012 $ 2,117 (a) $ 5,636 $ 7,753

2011 $ 4,806 $ 6,035 $ 10,841

2010 $ 3,295 $ 4,269 $ 7,564

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

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

For the years ended December 31, (in millions)

United States

Federal

State

and Local Foreign Total

2012

Current $ (401) $ 8 $ 2,383 $ 1,990

Deferred 1,046 41 41 1,128

$ 645 $ 49 $ 2,424 $ 3,118

2011

Current $ 320 $ 88 $ 2,357 $ 2,765

Deferred 1,340 47 49 1,436

$ 1,660 $ 135 $ 2,406 $ 4,201

2010

Current $ 614 $ 79 $ 1,896 $ 2,589

Deferred 390 4 12 406

$ 1,004 $ 83 $ 1,908 $ 2,995

58
The following reconciliation of the United States federal statutory income tax rate to Occidental’s worldwide effective tax rate on income from

continuing operations is stated as a percentage of pre-tax income:

For the years ended December 31, 2012 2011 2010

United States federal statutory tax rate 35 % 35 % 35 %

Operations outside the United States 5 4 5

State income taxes, net of federal benefit 1 1 1

Other (1) ( 1) ( 1)

Worldwide effective tax rate 40 % 39 % 40 %

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

2012 2011

Tax effects of temporary differences (in millions) Deferred Tax Assets

Deferred Tax

Liabilities Deferred Tax Assets

Deferred Tax

Liabilities

Property, plant and equipment differences $ — $ 7,316 $ — $ 6,039

Equity investments, partnerships and foreign subsidiaries — 351 — 351

Environmental reserves 126 — 131 —

Postretirement benefit accruals 413 — 410 —

Deferred compensation and benefits 278 — 286 —

Asset retirement obligations 367 — 318 —

Foreign tax credit carryforwards 1,277 — 1,240 —

Other tax credit carryforwards 195 — — —

Federal benefit of state income taxes 89 — 104 —

All other 334 161 374 116

Subtotal 3,079 7,828 2,863 6,506

Valuation allowance (1,040) — (1,003) —

Total deferred taxes $ 2,039 $ 7,828 $ 1,860 $ 6,506

Included in total deferred tax assets was a current portion aggregating $250 million and $200 million as of December 31, 2012 and 2011,

respectively, that was reported in other current assets. Total deferred tax assets were $2.0 billion and $1.9 billion as of December 31, 2012 and

2011, respectively, the noncurrent portion of which is netted against deferred tax liabilities. Occidental expects to realize the recorded deferred tax

assets, net of any allowances, through future operating income and reversal of temporary differences.

Occidental had, as of December 31, 2012, foreign tax credit carryforwards of $1.3 billion, which expire in varying amounts through 2022, and

various state operating loss carryforwards, which have varying carryforward periods through 2025. Substantially all of Occidental's valuation

allowance is provided for foreign tax credit and state operating loss carryforwards.

A deferred tax liability has not been recognized for temporary differences related to unremitted earnings of certain consolidated foreign

subsidiaries aggregating approximately $8.1 billion at December 31, 2012, as it is Occidental’s intention, generally, to reinvest such earnings

permanently. If the earnings of these foreign subsidiaries were not indefinitely reinvested, an additional deferred tax liability of approximately

$116 million would be required, assuming utilization of available foreign tax credits.

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

$26 million in 2010.

Additional paid-in capital was credited $8 million in 2012, $14 million in 2011 and $22 million in 2010 for an excess tax benefit from the

exercise of certain stock-based compensation awards.

As of December 31, 2012, Occidental had liabilities for unrecognized tax benefits of approximately $76 million included in deferred credits

and other liabilities – other, all of which, if subsequently recognized, would favorably affect Occidental’s effective tax rate.

5 9
A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:

For the years ended December 31, (in millions) 2012 2011

Balance at January 1, $ 67 $ 38

Additions based on tax positions related to the current year 16 44

Reductions based on tax positions related to prior years and settlements (7) (15)

Balance at December 31, $ 76 $ 67

Occidental records estimated potential interest and penalties related to liabilities for unrecognized tax benefits in the provisions for domestic

and foreign income taxes and these amounts were not material for the years ended December 31, 2012, 2011 and 2010.

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

Management believes it is unlikely that Occidental’s liabilities for unrecognized tax benefits related to existing matters would increase or

decrease within the next twelve months by a material amount. Occidental cannot reasonably estimate a range of potential changes in such

benefits due to the unresolved nature of the various audits.

NOTE 11 STOCKHOLDERS' EQUITY

The following is a summary of common stock issuances:

Shares in thousands Common Stock

Balance, December 31, 2009 883,643

Issued 967

Options exercised and other, net 665

Balance, December 31, 2010 885,275

Issued 1,302

Options exercised and other, net 232

Balance, December 31, 2011 886,809

Issued 1,746

Options exercised and other, net 246

Balance, December 31, 2012 888,801

TREASURY STOCK

Occidental has had a 95 million share repurchase program authorized since 2008; however, the program does not obligate Occidental to

acquire any specific number of shares and may be discontinued at any time. In 2012 and 2011, respectively, Occidental purchased 7.2 million

and 2.7 million shares under the program at an average cost of $77.98 and $77.12 per share.

Additionally, Occidental purchased shares from the trustee of its defined contribution savings plan during the years ended December 31,

2012, 2011 and 2010.

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

NONREDEEMABLE PREFERRED STOCK

Occidental has authorized 50,000,000 shares of preferred stock with a par value of $1.00 per share. At December 31, 2012, 2011 and 2010,

Occidental had no outstanding shares of preferred stock.

60
EARNINGS PER SHARE

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

In millions, except per-share amounts 2012 2011 2010

Basic EPS

Income from continuing operations $ 4,635 (a) $ 6,640 $ 4,641

Less: Income from continuing operations attributable to noncontrolling interest — — (72)

Income from continuing operations attributable to common stock 4,635 6,640 4,569

Discontinued operations, net (37) 131 (39)

Net income attributable to common stock 4,598 6,771 4,530

Less: Net income allocated to participating securities (8) (11) (6)

Net income attributable to common stock, net of participating securities $ 4,590 $ 6,760 $ 4,524

Weighted average number of basic shares 809.3 812.1 812.5

Basic EPS $ 5.67 $ 8.32 $ 5.57

Diluted EPS

Net income attributable to common stock, net of participating securities $ 4,590 $ 6,760 $ 4,524

Weighted average number of basic shares 809.3 812.1 812.5

Dilutive effect of potentially dilutive securities 0.7 0.8 1.3

Total diluted weighted average common shares 810.0 812.9 813.8

Diluted EPS $ 5.67 $ 8.32 $ 5.56

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

ACCUMULATED OTHER COMPREHENSIVE LOSS

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

Balance at December 31, (in millions) 2012 2011

Foreign currency translation adjustments $ (34) $ (9)

Unrealized gains (losses) on derivatives (7) 1

Pension and post-retirement adjustments (a) (461) (475)

Total $ (502) $ (483)

(a) See Note 13 for further information.

NOTE 12 STOCK-BASED INCENTIVE PLANS

Occidental has established several Plans that allow it to issue stock-based awards in the form of RSUs, stock options (Options), stock

appreciation rights (SARs) and TSRIs. An aggregate of 66 million shares of Occidental common stock were authorized for issuance and

approximately 15 million shares had been issued through December 31, 2012. Of the remaining shares, approximately 19 million shares are

available for grants of future awards because a plan provision requires each share covered by an award (other than Options and SARs) to be

counted as if three shares were issued in determining the number of shares that otherwise would have been available for future awards. Further,

the number of shares available for future awards may be less than 19 million depending on the type of award granted. Additionally, under the

plan, the shares available for future awards may increase by the number of shares currently unvested or forfeitable, or three times that number

as applicable, that (i) fail to vest, (ii) are forfeited or cancelled, or (iii) correspond to the portion of any stock-based awards settled in cash.

During 2012, non-employee directors were granted awards for 53,800 shares of restricted stock that fully vested on the grant date.

Compensation expense for these awards was measured using the quoted market price of Occidental's common stock on the grant date and was

fully recognized at that time.

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

For the years ended December 31, (in millions) 2012 2011 2010

Compensation expense $ 78 $ 110 $ 136

Income tax benefit recognized in the income statement $ 29 $ 40 $ 50

Intrinsic value of options and stock-settled SARs exercised $ 18 $ 21 $ 74

Cash paid (a) $ 83 $ 124 $ 97

Fair value of RSUs and TSRIs vested during the year (b) $ 28 $ 53 $ 19

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

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

61
As of December 31, 2012, unrecognized compensation expense for all unvested stock-based incentive awards, based on year-end valuation,

was $196 million. This expense is expected to be recognized over a weighted-average period of 2.1 years.

RSUs

Certain employees are awarded the right to receive RSUs, some of which have performance criteria, and are, or are equivalent in value to,

actual shares of Occidental common stock and are settled in cash or stock at the time of vesting. These awards vest at the end of, or ratably over,

two or three years from the grant date, however, certain of the RSUs are forfeitable if performance objectives are not satisfied between the third

and seventh anniversaries after the grant date. For those awards that cliff vest in two years, dividend equivalents are accumulated during the

vesting period and are paid when they vest. For the remaining RSUs, dividend equivalents are paid during the vesting period. The weightedaverage, grant-date fair values of cash-settled RSUs granted in 2012, 2011 and 2010 were $84.38, $104.74 and $77.14 per share, respectively.

The weighted-average, grant-date fair values of the stock-settled RSUs granted in 2012, 2011, and 2010 were $84.81, $102.97 and $84.29

respectively.

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

Cash-Settled Stock-Settled

RSUs

(000's)

Weighted-Average

Grant-Date

Fair Value

RSUs

(000's)

Weighted-Average

Grant-Date

Fair Value

Unvested at January 1 1,272 $ 90.50 568 $ 93.14

Granted 729 $ 84.38 824 $ 84.81

Vested (621) $ 83.61 (9) $ 88.21

Forfeitures (48) $ 92.90 (8) $ 84.57

Unvested at December 31 1,332 $ 90.27 1,375 $ 88.23

STOCK OPTIONS AND SARs

Certain employees have been granted Options that are settled in stock and SARs that are settled either only in stock or only in cash. No

Options or SARs have been granted since 2006 and all outstanding awards are vested. Exercise prices of the Options and SARs were equal to the

quoted market value of Occidental’s stock on the grant date. Generally, the Options and SARs vest ratably over three years from the grant date

with a maximum term of ten years. These Options and SARs may be forfeited or accelerated under certain circumstances.

The fair value of each Option, stock-settled SAR or cash-settled SAR is initially measured on the grant date using the Black Scholes option

valuation model. The expected life is estimated based on the actual weighted-average life of historical exercise activity of the grantee population at

the grant date. The volatility factors are based on the historical volatilities of Occidental common stock over the expected lives as estimated on the

grant date. The risk-free interest rate is the implied yield available on zero coupon T-notes (US Treasury Strip) at the grant date with a remaining

term equal to the expected life of the measured instrument. The dividend yield is the expected annual dividend yield over the expected life,

expressed as a percentage of the stock price on the grant date. Estimates of fair value may not accurately predict the value ultimately realized by

employees who receive stock-based incentive awards, and the ultimate value may not be indicative of the reasonableness of the original estimates

of fair value made by Occidental.

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

Cash-Settled Stock-Settled

SARs

(000's)

WeightedAverage

Exercise

Price

WeightedAverage

Remaining

Contractual

Term (yrs)

Aggregate

Intrinsic

Value

(000’s)

SARs &

Options

(000's)

WeightedAverage

Exercise

Price

WeightedAverage

Remaining

Contractual

Term (yrs)

Aggregate

Intrinsic

Value

(000’s)

Beginning balance,

January 1 564 $ 24.66 782 $ 26.34

Exercised (70) $ 24.66 (245) $ 14.22

Ending balance,

December 31 494 $ 24.66 1.5 $ 25,639 537 $ 31.88 2.0 $ 24,008

Exercisable at

December 31 494 $ 24.66 1.5 $ 25,639 537 $ 31.88 2.0 $ 24,008

62
TSRIs

Certain executives are awarded TSRIs that vest at the end of the three- or four-year period following the grant date if performance targets are

certified as being met. TSRIs granted in July 2012 have payouts that range from 0 to 100 percent of the maximum award that would settle, once

certified, fully in stock. TSRIs granted in July 2011 and October 2010 have payouts that range from 0 to 100 percent of the maximum award that

would settle, once certified, 50 percent in stock and 50 percent in cash. TSRIs granted in July 2009 have payouts that ranged from 0 to 200

percent of the target award that would settle, once certified, 60 percent in stock and 40 percent in cash. TSRIs granted in July 2008 had payouts of

150 percent of the target award and were certified and settled equally in stock and cash in 2012. Dividend equivalents for TSRI target shares are

paid during the performance period regardless of the payout range or settlement provision, except for the TSRIs issued in 2010, 2011 and 2012, for

which cumulative dividends will be paid upon vesting for the number of vested shares.

The fair values of TSRIs are initially determined on the grant date using a Monte Carlo simulation model based on Occidental's assumptions,

noted in the following table, and the volatility from corresponding peer group companies. The expected life is based on the vesting period (Term).

The risk-free interest rate is the implied yield available on zero coupon T-notes (US Treasury Strip) at the time of grant with a remaining term

equal to the Term. The dividend yield is the expected annual dividend yield over the Term, expressed as a percentage of the stock price on the

grant date. Estimates of fair value may not accurately predict the value ultimately realized by the employees who receive the awards, and the

ultimate value may not be indicative of the reasonableness of the original estimates of fair value made by Occidental.

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

TSRIs

Year Granted 2012 2011 2010

Assumptions used:

Risk-free interest rate 0.4% 0.6% 0.6%

Dividend yield 2.6% 1.8% 1.8%

Volatility factor 34% 33% 32%

Expected life (years) 3 3 3

Grant-date fair value of underlying Occidental common stock $ 84.57 $ 102.97 $ 84.29

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

below:

TSRIs

Awards

(000’s)

Weighted-Average

Grant-Date Fair

Value of Occidental Stock

Unvested at January 1 (a) 1,865 $ 78.67

Granted (a) 453 $ 84.57

Vested (b) (388) $ 77.00

Forfeitures — $ —

Unvested at December 31 (a) 1,930 $ 80.39

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

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

63
NOTE 13 RETIREMENT AND POSTRETIREMENT BENEFIT PLANS

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

DEFINED CONTRIBUTION PLANS

All domestic employees and certain foreign national employees are eligible to participate in one or more of the defined contribution retirement

or savings plans that provide for periodic contributions by Occidental based on plan-specific criteria, such as base pay, age, level and employee

contributions. Certain salaried employees participate in a supplemental retirement plan that restores benefits lost due to governmental limitations

on qualified retirement benefits. The accrued liabilities for the supplemental retirement plan were $145 million and $126 million as of

December 31, 2012 and 2011, respectively, and Occidental expensed $137 million in 2012, $110 million in 2011 and $101 million in 2010 under

the provisions of these defined contribution and supplemental retirement plans.

DEFINED BENEFIT PLANS

Participation in defined benefit plans is limited and approximately 1,000 domestic and 1,600 foreign national employees, mainly union,

nonunion hourly and certain employees that joined Occidental from acquired operations with grandfathered benefits, are currently accruing

benefits under these plans.

Pension costs for Occidental’s defined benefit pension plans, determined by independent actuarial valuations, are generally funded by

payments to trust funds, which are administered by independent trustees.

POSTRETIREMENT AND OTHER BENEFIT PLANS

Occidental provides medical and dental benefits and life insurance coverage for certain active, retired and disabled employees and their

eligible dependents. Occidental generally funds the benefits as they are paid during the year. These benefit costs, including the postretirement

costs, were approximately $218 million in 2012, $194 million in 2011 and $180 million in 2010.

64
OBLIGATIONS AND FUNDED STATUS

The following tables show the amounts recognized in the consolidated balance sheets of Occidental related to its pension and postretirement

benefit plans and their funding status, obligations and plan asset fair values (in millions):

Pension Benefits Postretirement Benefits

As of December 31, 2012 2011 2012 2011

Amounts recognized in the consolidated balance sheet:

Other assets $ 24 $ 24 $ — $ —

Accrued liabilities (4) (5) (59) (47)

Deferred credits and other liabilities — other (136) (136) (1,068) (1,045)

$ (116) $ (117) $ (1,127) $ (1,092)

AOCI included the following after-tax balances:

Net loss $ 134 $ 146 $ 324 $ 331

Prior service cost 1 2 2 2

$ 135 $ 148 $ 326 $ 333

For the years ended December 31,

Changes in benefit obligation:

Benefit obligation — beginning of year $ 592 $ 615 $ 1,092 $ 991

Service cost — benefits earned during the period 13 12 25 22

Interest cost on projected benefit obligation 27 29 42 45

Actuarial loss 46 49 26 81

Foreign currency exchange rate (gain) loss 2 (5) — —

Benefits paid (57) (51) (58) (47)

Settlements (8) (57) — —

Benefit obligation — end of year $ 615 $ 592 $ 1,127 $ 1,092

Changes in plan assets:

Fair value of plan assets — beginning of year $ 475 $ 495 $ — $ —

Actual return on plan assets 61 13 — —

Foreign currency exchange rate gain (loss) (3) (3) — —

Employer contributions 31 78 — —

Benefits paid (57) (51) — —

Settlements (8) (57) — —

Fair value of plan assets — end of year $ 499 $ 475 $ — $ —

Unfunded status: $ (116) $ (117) $ (1,127) $ (1,092)

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

Accumulated Benefit

Obligation in Excess of

Plan Assets

Plan Assets

in Excess of Accumulated

Benefit Obligation

As of December 31, (in millions) 2012 2011 2012 2011

Projected Benefit Obligation $ 305 $ 361 $ 310 $ 231

Accumulated Benefit Obligation $ 278 $ 334 $ 305 $ 227

Fair Value of Plan Assets $ 171 $ 226 $ 328 $ 249

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

6 5
COMPONENTS OF NET PERIODIC BENEFIT COST

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

Pension Benefits Postretirement Benefits

For the years ended December 31, (in millions) 2012 2011 2010 2012 2011 2010

Net periodic benefit costs:

Service cost — benefits earned during the period $ 13 $ 12 $ 16 $ 25 $ 22 $ 19

Interest cost on benefit obligation 27 29 30 42 45 44

Expected return on plan assets (31) (33) (31) — — —

Recognized actuarial loss 19 13 15 37 31 27

Other costs and adjustments 17 — 10 1 1 1

Net periodic benefit cost $ 45 $ 21 $ 40 $ 105 $ 99 $ 91

The estimated net loss and prior service cost for the defined benefit pension plans that will be amortized from AOCI into net periodic benefit

cost over the next fiscal year are $17 million and $0, respectively. The estimated net loss and prior service cost for the defined benefit

postretirement plans that will be amortized from AOCI into net periodic benefit cost over the next fiscal year are $37 million and $1 million,

respectively.

ADDITIONAL INFORMATION

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

for domestic plans:

Pension Benefits Postretirement Benefits

For the years ended December 31, 2012 2011 2012 2011

Benefit Obligation Assumptions:

Discount rate 3.59% 4.12% 3.89% 4.12%

Rate of compensation increase 4.00% 4.00% — —

Net Periodic Benefit Cost Assumptions:

Discount rate 4.12% 4.74% 4.12% 4.74%

Assumed long term rate of return on assets 6.50% 6.50% — —

Rate of compensation increase 4.00% 4.00% — —

For domestic pension plans and postretirement benefit plans, Occidental based the discount rate on the Aon/Hewitt AA-AAA Universe yield

curve in 2012 and 2011. The weighted-average rate of increase in future compensation levels is consistent with Occidental’s past and anticipated

future compensation increases for employees participating in retirement plans that determine benefits using compensation. The assumed longterm rate of return on assets is estimated with regard to current market factors but within the context of historical returns. Occidental considers

historical returns and correlation of equities and fixed-income securities and current market factors such as inflation and interest rates.

For pension plans outside the United States, Occidental based its discount rate on rates indicative of government or investment grade

corporate debt in the applicable country, taking into account hyperinflationary environments when necessary. The discount rates used for the

foreign pension plans ranged from 1.5 percent to 10.0 percent at both December 31, 2012 and 2011. The average rate of increase in future

compensation levels ranged from 1.5 percent to 10.0 percent in 2012, depending on local economic conditions. The expected long-term rate of

return on plan assets was 6.5 percent and 5.8 percent in excess of local inflation in 2012 and 2011, respectively.

The postretirement benefit obligation was determined by application of the terms of medical and dental benefits and life insurance coverage,

including the effect of established maximums on covered costs, together with relevant actuarial assumptions and healthcare cost trend rates

projected at an assumed U.S. Consumer Price Index (CPI) increase of 2.39 percent and 2.04 percent as of December 31, 2012 and 2011,

respectively. Since 1993, participants other than certain union employees have paid for all medical cost increases in excess of increases in the

CPI. For those union employees, Occidental projected that healthcare cost trend rates would decrease 0.5 percent per year from 8.5 percent in

2012 until they reach 6.0 percent in 2017, and remain at 6.0 percent thereafter. A 1-percent increase or a 1-percent decrease in these assumed

healthcare cost trend rates would result in an increase of $44 million or a reduction of $37 million, respectively, in the postretirement benefit

obligation as of December 31, 2012. The annual service and interest costs would not be materially affected by these changes.

The actuarial assumptions used could change in the near term as a result of changes in expected future trends and other factors that,

depending on the nature of the changes, could cause increases or decreases in the plan assets and liabilities.

6 6
FAIR VALUE OF PENSION PLAN ASSETS

Occidental employs a total return investment approach that uses a diversified blend of equity and fixed-income investments to optimize the

long-term return of plan assets at a prudent level of risk. The investments are monitored by Occidental’s Investment Committee in its role as

fiduciary. The Investment Committee, consisting of senior Occidental executives, selects and employs various external professional investment

management firms to manage specific investments across the spectrum of asset classes. Equity investments are diversified across United States

and non-United States stocks, as well as differing styles and market capitalizations. Other asset classes such as private equity and real estate may

be used with the goals of enhancing long-term returns and improving portfolio diversification. The target allocation of plan assets is 60 percent

equity securities and 40 percent debt securities. Investment performance is measured and monitored on an ongoing basis through quarterly

investment portfolio and manager guideline compliance reviews, annual liability measurements and periodic studies.

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

Fair Value Measurements at December 31, 2012 Using

Description Level 1 Level 2 Level 3 Total

Asset Class:

U.S. government securities $ 24 $ — $ — $ 24

Corporate bonds (a) — 83 — 83

Common/collective trusts (b) — 11 — 11

Mutual funds:

Bond funds 84 — — 84

Blend funds 106 — — 106

Value and growth funds 5 — — 5

Common and preferred stocks (c) 146 — — 146

Other — 35 11 46

Total pension plan assets (d) $ 365 $ 129 $ 11 $ 505

Fair Value Measurements at December 31, 2011 Using

Description Level 1 Level 2 Level 3 Total

Asset Class:

U.S. government securities $ 22 $ — $ — $ 22

Corporate bonds (a) — 83 — 83

Common/collective trusts (b) — 14 — 14

Mutual funds:

Bond funds 84 — — 84

Blend funds 97 — — 97

Value and growth funds 5 — — 5

Common and preferred stocks (c) 131 — — 131

Other — 34 12 46

Total pension plan assets (d) $ 339 $ 131 $ 12 $ 482

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

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

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

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

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

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

67
Estimated future benefit payments, which reflect expected future service, as appropriate, are as follows:

For the years ended December 31, (in millions)

Pension

Benefits Postretirement Benefits

2013 $ 40 $ 50

2014 $ 44 $ 51

2015 $ 41 $ 52

2016 $ 46 $ 53

2017 $ 42 $ 54

2018 — 2022 $ 230 $ 294

NOTE 14 INVESTMENTS AND RELATED-PARTY TRANSACTIONS

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

investments, respectively.

EQUITY INVESTMENTS

As of December 31, 2012, Occidental’s equity investments consisted mainly of a 35-percent interest in the general partner of Plains Pipeline,

a 24.5-percent interest in the stock of Dolphin Energy, and various other partnerships and joint ventures. Equity investments paid dividends of

$526 million, $349 million and $217 million to Occidental in 2012, 2011 and 2010, respectively. As of December 31, 2012, cumulative

undistributed earnings of equity-method investees since their respective acquisitions were approximately $240 million. As of December 31, 2012,

Occidental's investments in equity investees exceeded the underlying equity in net assets by $1.1 billion, of which $1 billion represented

goodwill and the remainder comprised intangibles amortized over their estimated useful lives.

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

For the years ended December 31, (in millions) 2012 2011 2010

Revenues $ 2,667 $ 2,439 $ 1,759

Costs and expenses 2,310 2,046 1,482

Net income $ 357 $ 393 $ 277

As of December 31, (in millions) 2012 2011

Current assets $ 2,065 $ 2,230

Non-current assets $ 5,104 $ 4,381

Current liabilities $ 1,774 $ 1,532

Long-term debt $ 2,250 $ 2,305

Other non-current liabilities $ 241 $ 168

Stockholders’ equity $ 2,904 $ 2,606

Occidental’s investment in Dolphin, which was acquired in 2002, consists of two separate economic interests through which Occidental owns

(i) a 24.5-percent undivided interest in the operations under an agreement which is proportionately consolidated in the financial statements; and

(ii) a 24.5-percent interest in the stock of Dolphin Energy, which is accounted for as an equity investment.

During 2010, Occidental had a 50-percent joint interest in EHP, which was accounted for as an equity method investment. On December 31,

2010, Occidental completed its acquisition of the remaining 50-percent interest, bringing its total ownership to 100 percent. EHP was consolidated

in Occidental's balance sheet as of December 31, 2010.

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RELATED-PARTY TRANSACTIONS

Occidental from time to time purchases oil, NGLs, power, steam and chemicals from and sells oil, NGLs, gas, chemicals and power to certain

of its equity investees at market-related prices. During 2012, 2011 and 2010, Occidental entered into the following related-party transactions and

had the following amounts due from or to its related parties:

December 31, (in millions) 2012 2011 2010

Purchases (a) $ 8 $ 10 $ 153

Sales (b) $ 419 $ 392 $ 440

Services $ 17 $ 10 $ 2

Advances and amounts due from $ 25 $ 32 $ 135

Amounts due to $ 129 $ 21 $ 383

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

(b) In 2012, 2011 and 2010, sales of Occidental-produced oil and NGLs to Plains Pipeline accounted for 80 percent, 76 percent and 50 percent of these totals, respectively. Additionally,

Occidental conducts marketing and trading activities with Plains Pipeline for oil and NGLs. These transactions are reported in Occidental's income statement on a net margin basis.

The sales amounts above include the net margins on such transactions, which were negligible. In 2012 and 2011, sales to Dolphin Energy accounted for 12 percent and 16 percent, of

total sales, respectively. In 2010, sales to EHP and Dolphin Energy accounted for 44 percent of total sales.

NOTE 15 FAIR VALUE MEASUREMENTS

FAIR VALUES – RECURRING

The following tables provide fair value measurement information for assets and liabilities that are measured on a recurring basis as of

December 31, 2012 and 2011 (in millions):

Fair Value Measurements at December 31, 2012 Using

Netting and

Collateral (a)

Total

Description Level 1 Level 2 Level 3 Fair Value

Assets:

Commodity derivatives $ 107 $ 312 $ — $ (301) $ 118

Liabilities:

Commodity derivatives $ 99 $ 398 $ — $ (371) $ 126

Fair Value Measurements at December 31, 2011 Using

Netting and

Collateral (a)

Total

Description Level 1 Level 2 Level 3 Fair Value

Assets:

Commodity derivatives $ 310 $ 640 $ — $ (758) $ 192

Liabilities:

Commodity derivatives $ 311 $ 652 $ — $ (782) $ 181

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

6 9
FAIR VALUES – NONRECURRING

Occidental performed impairment tests with respect to its proved and unproved properties due to the negative revisions to certain of its natural

gas reserves and the continued deterioration of natural gas prices. The impairment tests, including the fair value estimation, incorporate a

number of assumptions involving expectations of future cash flows. These assumptions include estimates of future product prices, which

Occidental bases on forward price curves and, where applicable, contractual prices, estimates of oil and gas reserves, estimates of future expected

operating and development costs and appropriate discount rates.

In 2012, Occidental recorded pre-tax impairment charges of $1.7 billion, almost all of which were for certain assets in Midcontinent, over 90

percent of which were related to natural gas properties, which were acquired more than four years ago on average. These properties were

impacted by persistently low natural gas prices in the United States changing management's development plans and negative reserve revisions

due to recent well performance. In 2010, Occidental recorded a pre-tax impairment charge of $275 million, predominantly of gas properties in the

Rocky Mountain region. Occidental used the income approach to measure the fair value of these properties, using inputs categorized as Level 3 in

the fair value hierarchy.

FINANCIAL INSTRUMENTS FAIR VALUE

The carrying amounts of cash and cash equivalents and other on-balance-sheet financial instruments, other than fixed-rate debt,

approximate fair value. The cost, if any, to terminate off-balance-sheet financial instruments is not significant.

NOTE 16 INDUSTRY SEGMENTS AND GEOGRAPHIC AREAS

Occidental conducts its continuing operations through three segments: (1) oil and gas; (2) chemical; and (3) midstream and marketing. The oil

and gas segment explores for, develops and produces oil and condensate, NGLs, and natural gas. The chemical segment mainly manufactures

and markets basic chemicals and vinyls. The midstream and marketing segment gathers, processes, transports, stores, purchases and markets

oil, condensate, NGLs, natural gas, CO2 and power. It also trades around its assets, including transportation and storage capacity, and trades oil,

NGLs, gas and other commodities. The segment also invests in entities that conduct similar activities.

Earnings of industry segments and geographic areas exclude income taxes, interest income, interest expense, environmental remediation

expenses, unallocated corporate expenses and discontinued operations, but include gains and losses from dispositions of segment and geographic

area assets and income from the segments' equity investments. Intersegment sales eliminate upon consolidation and are generally made at prices

approximating those that the selling entity would be able to obtain in third-party transactions.

Identifiable assets are those assets used in the operations of the segments. Corporate assets consist of cash, certain corporate receivables and

PP&E, and an investment in the Joslyn, Canada oil sands project.

70
Industry Segments

In millions

Oil and Gas Chemical

Midstream

and

Marketing

Corporate

and

Eliminations Total

YEAR ENDED DECEMBER 31, 2012

Net sales $ 18,906 (a) $ 4,580 (b) $ 1,399 (c) $ (713) $ 24,172

Pretax operating profit (loss) $ 7,095 (d) $ 720 $ 439 $ (501) (f,h) $ 7,753

Income taxes — — — (3,118) (g,h) (3,118)

Discontinued operations, net — — — (37) (37)

Net income (loss) attributable to common stock $ 7,095 $ 720 $ 439 $ (3,656) $ 4,598

Investments in unconsolidated entities $ 113 $ 108 $ 1,662 $ 11 $ 1,894

Property, plant and equipment additions, net (i) $ 8,282 $ 365 $ 1,612 $ 91 $ 10,350

Depreciation, depletion and amortization $ 3,933 $ 345 $ 206 $ 27 $ 4,511

Total assets $ 44,004 $ 3,854 $ 12,762 $ 3,590 $ 64,210

YEAR ENDED DECEMBER 31, 2011

Net sales $ 18,419 (a) $ 4,815 (b) $ 1,447 (c) $ (742) $ 23,939

Pretax operating profit (loss) $ 10,241 (d) $ 861 $ 448 $ (709) (f,h) $ 10,841 (d)

Income taxes — — — (4,201) (g,h) (4,201)

Discontinued operations, net — — — 131 131

Net income (loss) attributable to common stock $ 10,241 (d) $ 861 $ 448 $ (4,779) $ 6,771

Investments in unconsolidated entities $ 128 $ 121 $ 1,812 $ 1 1 $ 2,072

Property, plant and equipment additions, net (i) $ 6,192 $ 241 $ 1,120 $ 51 $ 7,604

Depreciation, depletion and amortization $ 3,064 $ 330 $ 173 $ 24 $ 3,591

Total assets $ 38,967 $ 3,754 $ 11,962 $ 5,361 $ 60,044

YEAR ENDED DECEMBER 31, 2010

Net sales $ 14,276 (a) $ 4,016 (b) $ 1,471 (c) $ (718) $ 19,045

Pretax operating profit (loss) $ 7,151 (d,e) $ 438 $ 472 $ (497) (f,h) $ 7,564 (d,e)

Income taxes — — — (2,995) (g,h) (2,995)

Discontinued operations, net — — — (39) (39)

Net income (loss) attributable to common stock $ 7,151 (d,e) $ 438 $ 472 $ (3,531) $ 4,530 (e)

Investments in unconsolidated entities $ 123 $ 135 $ 1,770 $ 1 1 $ 2,039

Property, plant and equipment additions, net (i) $ 3,211 $ 248 $ 537 $ 38 $ 4,034

Depreciation, depletion and amortization $ 2,668 $ 321 $ 142 $ 22 $ 3,153

Total assets $ 31,855 $ 3,755 $ 10,445 $ 6,377 (j) $ 52,432

(See footnotes on next page)

71
Footnotes:

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

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

Basic Chemicals Vinyls Other Chemicals

Year ended December 31, 2012 57% 40% 3%

Year ended December 31, 2011 58% 39% 3%

Year ended December 31, 2010 57% 40% 3%

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

Gas Processing Power

Marketing, Trading,

Transportation and other

Year ended December 31, 2012 59% 20% 21%

Year ended December 31, 2011 64% 27% 9%

Year ended December 31, 2010 52% 27% 21%

(d) The 2012 amount includes pre-tax charges of $1.7 billion for the impairment of domestic gas assets and related items. The 2011 amount includes pre-tax charges of $35 million related to

exploration write-offs in Libya and $29 million related to a Colombian net worth tax, and a pre-tax gain for the sale of an interest in a Colombian pipeline of $22 million. The 2010

amount includes a $275 million pre-tax charge for asset impairments, predominantly of gas properties in the Rocky Mountain region. 

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

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

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

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

Benefit (Charge) (In millions) 2012 2011 2010

CORPORATE

Pre-tax operating profit (loss)

Premium on debt extinguishments $ — $ (163) $ —

Litigation reserves (20) — —

$ (20) $ (163) $ —

Income taxes

State income tax charge $ — $ (33) $ —

Foreign tax credit carryforwards — — 80

Tax effect of pre-tax adjustments * 636 50 100

$ 636 $ 17 $ 180

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

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

for 2010.

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

GEOGRAPHIC AREAS

In millions

Net sales (a) Property, plant and equipment, net

For the years ended December 31, 2012 2011 2010 2012 2011 2010

United States $ 15,359 $ 15,040 $ 12,151 $ 40,786 $ 36,283 $ 28,571

Foreign

Qatar 3,356 3,432 2,677 2,676 2,735 2,823

Oman 2,578 2,500 1,666 2,353 2,143 1,967

Colombia 1,027 1,054 999 1,041 854 715

Yemen 407 907 766 199 245 347

Bahrain 215 187 100 688 477 222

United Arab Emirates — — — 2,104 971 1

Other Foreign 1,230 819 686 2,217 1,976 1,890

Total Foreign 8,813 8,899 6,894 11,278 9,401 7,965

Total $ 24,172 $ 23,939 $ 19,045 $ 52,064 $ 45,684 $ 36,536

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

72
2012 Quarterly Financial Data (Unaudited) Occidental Petroleum Corporation

and Subsidiaries

In millions, except per-share amounts

Three months ended March 31 June 30 September 30 December 31

Segment net sales

Oil and gas $ 4,902 $ 4,495 $ 4,635 $ 4,874

Chemical 1,148 1,172 1,119 1,141

Midstream, marketing and other 393 262 389 355

Eliminations (175) (161) (178) (199)

Net sales $ 6,268 $ 5,768 $ 5,965 $ 6,171

Gross profit $ 3,144 $ 2,541 $ 2,617 $ 2,842

Segment earnings

Oil and gas $ 2,504 $ 2,043 $ 2,026 $ 522 (a)

Chemical 184 194 162 180

Midstream, marketing and other 131 77 156 75

2,819 2,314 2,344 777

Unallocated corporate items

Interest expense, net (28) (25) (34) (30)

Income taxes (1,139) (875) (855) (249)

Other (92) (82) (76) (134)

Income from continuing operations 1,560 1,332 1,379 364

Discontinued operations, net (1) (4) (4) (28)

Net income attributable to common stock $ 1,559 $ 1,328 $ 1,375 $ 336

Basic earnings per common share

Income from continuing operations $ 1.92 $ 1.64 $ 1.70 $ 0.45

Discontinued operations, net — — (0.01) (0.03)

Basic earnings per common share $ 1.92 $ 1.64 $ 1.69 $ 0.42

Diluted earnings per common share

Income from continuing operations $ 1.92 $ 1.64 $ 1.70 $ 0.45

Discontinued operations, net — — (0.01) (0.03)

Diluted earnings per common share $ 1.92 $ 1.64 $ 1.69 $ 0.42

Dividends per common share $ 0.54 $ 0.54 $ 0.54 $ 0.54

Market price per common share

High $ 106.68 $ 98.24 $ 93.60 $ 87.39

Low $ 91.85 $ 76.59 $ 82.25 $ 72.43

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

73
2011 Quarterly Financial Data (Unaudited) Occidental Petroleum Corporation

and Subsidiaries

In millions, except per-share amounts

Three months ended March 31 June 30 September 30 December 31

Segment net sales

Oil and gas $ 4,367 $ 4,591 $ 4,677 $ 4,784

Chemical 1,165 1,325 1,231 1,094

Midstream, marketing and other 412 441 256 338

Eliminations (218) (184) (158) (182)

Net sales $ 5,726 $ 6,173 $ 6,006 $ 6,034

Gross profit $ 3,049 $ 3,291 $ 2,975 $ 3,050

Segment earnings

Oil and gas $ 2,468 $ 2,624 $ 2,612 $ 2,537

Chemical 219 253 245 144

Midstream, marketing and other 114 187 77 70

2,801 3,064 2,934 2,751

Unallocated corporate items

Interest expense, net (214) (a) (22) (23) (25)

Income taxes (1,054) (1,111) (1,087) (949)

Other (128) (112) (49) (136)

Income from continuing operations 1,405 1,819 1,775 1,641

Discontinued operations, net 144 (2) (4) (7)

Net income attributable to common stock $ 1,549 $ 1,817 $ 1,771 $ 1,634

Basic earnings per common share

Income from continuing operations $ 1.72 $ 2.23 $ 2.18 $ 2.02

Discontinued operations, net 0.18 — (0.01) (0.01)

Basic earnings per common share $ 1.90 $ 2.23 $ 2.17 $ 2.01

Diluted earnings per common share

Income from continuing operations $ 1.72 $ 2.23 $ 2.18 $ 2.02

Discontinued operations, net 0.18 — (0.01) (0.01)

Diluted earnings per common share $ 1.90 $ 2.23 $ 2.17 $ 2.01

Dividends per common share $ 0.46 $ 0.46 $ 0.46 $ 0.46

Market price per common share

High $ 107.56 $ 117.89 $ 109.08 $ 101.65

Low $ 93.25 $ 95.67 $ 69.90 $ 66.36

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

74
Supplemental Oil and Gas Information (Unaudited)

The following tables set forth Occidental’s net interests in quantities of proved developed and undeveloped reserves of oil (including

condensate), NGLs and natural gas and changes in such quantities. Reserves are stated net of applicable royalties. Estimated reserves include

Occidental's economic interests under production sharing contracts (PSCs) and other similar economic arrangements. In addition, discussions of oil

and gas production or volumes, in general, refer to sales volumes unless the context requires or it is indicated otherwise.

Oil Reserves

In millions of barrels (MMbbl)

United Latin Middle East/

States America (a,b) North Africa (c) Total

PROVED DEVELOPED AND UNDEVELOPED RESERVES

Balance at December 31, 2009 1,385 95 494 1,974

Revisions of previous estimates — 2 (34) (32)

Improved recovery 82 9 42 133

Extensions and discoveries 1 — — 1

Purchases of proved reserves 72 — 30 102

Sales of proved reserves (d) — (3) — (3)

Production (80) (13) (70) (163)

Balance at December 31, 2010 1,460 90 462 2,012

Revisions of previous estimates (71) (3) (60) (134)

Improved recovery 135 16 50 201

Extensions and discoveries 8 4 3 15

Purchases of proved reserves 78 — — 78

Sales of proved reserves — — — —

Production (84) (11) (69) (164)

Balance at December 31, 2011 1,526 96 386 2,008

Revisions of previous estimates (70) 4 (3) (69)

Improved recovery 143 7 30 180

Extensions and discoveries 7 — 27 34

Purchases of proved reserves 54 — — 54

Sales of proved reserves — — — —

Production (93) (11) (67) (171)

Balance at December 31, 2012 1,567 96 373 2,036

PROVED DEVELOPED RESERVES

December 31, 2009 1,131 71 378 1,580

December 31, 2010 1,126 69 366 1,561

December 31, 2011 1,146 69 317 1,532

December 31, 2012 (e) 1,156 82 295 1,533

PROVED UNDEVELOPED RESERVES

December 31, 2009 254 24 116 394

December 31, 2010 334 21 96 451

December 31, 2011 380 27 69 476

December 31, 2012 (f) 411 14 78 503

(a) Proved reserves as of December 31, 2009 include proved oil reserves related to the noncontrolling interest of a Colombian subsidiary. On December 31, 2010, Occidental restructured its

Colombian operations to take a direct working interest in the related assets. As a result, the December 31, 2010, 2011 and 2012 proved reserves amounts exclude the noncontrolling

interest.

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

2009, respectively. 

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

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

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

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

75
NGL Reserves

In millions of barrels (MMbbl)

United Latin Middle East/

States America North Africa (a) Total

PROVED DEVELOPED AND UNDEVELOPED RESERVES

Balance at December 31, 2009 221 — 68 289

Revisions of previous estimates 8 — (2) 6

Improved recovery 16 — — 16

Extensions and discoveries — — — —

Purchases of proved reserves 1 1 — — 1 1

Sales of proved reserves — — — —

Production (19) — (5) (24)

Balance at December 31, 2010 237 — 61 298

Revisions of previous estimates — — (2) (2)

Improved recovery 10 — — 10

Extensions and discoveries 1 — — 1

Purchases of proved reserves 2 — — 2

Sales of proved reserves — — — —

Production (25) — (4) (29)

Balance at December 31, 2011 225 — 55 280

Revisions of previous estimates 1 — — 1

Improved recovery 16 — — 16

Extensions and discoveries — — 64 64

Purchases of proved reserves 1 — — 1

Sales of proved reserves — — — —

Production (27) — (3) (30)

Balance at December 31, 2012 216 — 116 332

PROVED DEVELOPED RESERVES

December 31, 2009 155 — 68 223

December 31, 2010 163 — 61 224

December 31, 2011 165 — 55 220

December 31, 2012 (b) 167 — 53 220

PROVED UNDEVELOPED RESERVES

December 31, 2009 66 — — 66

December 31, 2010 74 — — 74

December 31, 2011 60 — — 60

December 31, 2012 (c) 49 — 63 112

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

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

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

76
Gas Reserves

In billions of cubic feet (Bcf)

United Latin Middle East/

States America (a) North Africa (b) Total

PROVED DEVELOPED AND UNDEVELOPED RESERVES

Balance at December 31, 2009 2,799 53 2,175 5,027

Revisions of previous estimates (55) ( 1) (60) (116)

Improved recovery 344 10 87 441

Extensions and discoveries 7 — 12 19

Purchases of proved reserves 186 — — 186

Sales of proved reserves — — — —

Production (247) (6) (166) (419)

Balance at December 31, 2010 3,034 56 2,048 5,138

Revisions of previous estimates (369) (19) (78) (466)

Improved recovery 222 2 95 319

Extensions and discoveries 35 — 16 51

Purchases of proved reserves 728 — — 728

Sales of proved reserves — — — —

Production (285) (6) (156) (447)

Balance at December 31, 2011 3,365 33 1,925 5,323

Revisions of previous estimates (748) — 62 (686)

Improved recovery 317 11 34 362

Extensions and discoveries 19 — 784 803

Purchases of proved reserves 236 — — 236

Sales of proved reserves — — — —

Production (300) (5) (165) (470)

Balance at December 31, 2012 2,889 39 2,640 5,568

PROVED DEVELOPED RESERVES

December 31, 2009 1,931 51 1,759 3,741

December 31, 2010 2,007 50 1,665 3,722

December 31, 2011 2,365 32 1,555 3,952

December 31, 2012 (c) 2,121 36 1,816 3,973

PROVED UNDEVELOPED RESERVES

December 31, 2009 868 2 416 1,286

December 31, 2010 1,027 6 383 1,416

December 31, 2011 1,000 1 370 1,371

December 31, 2012 (d) 768 3 824 1,595

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

2009, respectively.

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

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

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

77
Total Reserves

In millions of BOE (MMBOE) (a)

United Latin Middle East/

States America (b,c) North Africa (d) Total

PROVED DEVELOPED AND UNDEVELOPED RESERVES

Balance at December 31, 2009 2,072 104 924 3,100

Revisions of previous estimates ( 1) 2 (46) (45)

Improved recovery 156 1 1 57 224

Extensions and discoveries 2 — 2 4

Purchases of proved reserves 114 — 30 144

Sales of proved reserves(e) — (3) — (3)

Production (140) (14) (103) (257)

Balance at December 31, 2010 2,203 100 864 3,167

Revisions of previous estimates (132) (7) (75) (214)

Improved recovery 182 16 66 264

Extensions and discoveries 15 4 6 25

Purchases of proved reserves 201 — — 201

Sales of proved reserves — — — —

Production (156) (12) (99) (267)

Balance at December 31, 2011 2,313 101 762 3,176

Revisions of previous estimates (194) 4 7 (183)

Improved recovery 212 9 36 257

Extensions and discoveries 10 — 222 232

Purchases of proved reserves 94 — — 94

Sales of proved reserves — — — —

Production (170) (12) (98) (280)

Balance at December 31, 2012 2,265 102 929 3,296

PROVED DEVELOPED RESERVES

December 31, 2009 1,608 80 739 2,427

December 31, 2010 1,624 78 705 2,407

December 31, 2011 1,707 74 631 2,412

December 31, 2012 (f) 1,677 8 8 651 2,416

PROVED UNDEVELOPED RESERVES

December 31, 2009 464 24 185 673

December 31, 2010 579 22 159 760

December 31, 2011 606 27 131 764

December 31, 2012 (g) 588 14 278 880

(a) Natural gas volumes have been converted to barrels of oil equivalent (BOE) based on energy content of six thousand cubic feet (Mcf) of gas to one barrel of oil. Barrels of oil equivalence

does not necessarily result in price equivalence. The price of natural gas on a barrel of oil equivalent basis is currently substantially lower than the corresponding price for oil and has

been similarly lower over the recent past. For example, in 2012, the average prices of West Texas Intermediate (WTI) oil and New York Mercantile Exchange (NYMEX) natural gas were

$94.21 per barrel and $2.81 per Mcf, respectively, resulting in an oil to gas ratio of over 30.

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

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

2009, respectively.

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

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

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

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

,

78
CAPITALIZED COSTS

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

United Latin Middle East/

In millions States America North Africa Total

December 31, 2012

Proved properties $ 42,563 $ 2,142 $ 15,873 $ 60,578

Unproved properties (a) 4,592 27 220 4,839

Total capitalized costs (b) 47,155 2,169 16,093 65,417

Accumulated depreciation, depletion and amortization (13,432) (1,068) (8,582) (23,082)

Net capitalized costs $ 33,723 $ 1,101 $ 7,511 $ 42,335

December 31, 2011

Proved properties $ 36,123 $ 1,861 $ 13,839 $ 51,823

Unproved properties (a) 4,675 — 184 4,859

Total capitalized costs (b) 40,798 1,861 14,023 56,682

Accumulated depreciation, depletion and amortization (11,063) (951) (7,178) (19,192)

Net capitalized costs $ 29,735 $ 910 $ 6,845 $ 37,490

December 31, 2010

Proved properties $ 28,516 $ 1,816 $ 12,231 $ 42,563

Unproved properties (a) 3,474 5 190 3,669

Total capitalized costs (b) 31,990 1,821 12,421 46,232

Accumulated depreciation, depletion and amortization (9,321) (1,050) (5,960) (16,331)

Net capitalized costs $ 22,669 $ 771 (c) $ 6,461 $ 29,901

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

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

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

COSTS INCURRED

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

United Latin Middle East/

In millions States America North Africa Total

FOR THE YEAR ENDED DECEMBER 31, 2012

Property acquisition costs

Proved properties $ 1,689 $ — $ 14 $ 1,703

Unproved properties 613 — — 613

Exploration costs 539 1 114 654

Development costs 5,344 304 2,025 7,673

Costs incurred $ 8,185 $ 305 $ 2,153 $ 10,643

FOR THE YEAR ENDED DECEMBER 31, 2011

Property acquisition costs

Proved properties $ 3,185 $ — $ — $ 3,185

Unproved properties 1,311 — 32 1,343

Exploration costs 400 33 87 520

Development costs 4,100 214 1,495 5,809

Costs incurred $ 8,996 $ 247 $ 1,614 $ 10,857

FOR THE YEAR ENDED DECEMBER 31, 2010

Property acquisition costs

Proved properties $ 2,084 $ — $ 63 $ 2,147

Unproved properties 2,290 — — 2,290

Exploration costs 177 13 126 316

Development costs 1,674 178 1,231 3,083

Costs incurred $ 6,225 $ 191 (a) $ 1,420 $ 7,836

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

incurred of $448 million.

79
RESULTS OF OPERATIONS

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

interest and royalties, were as follows:

United Latin Middle East/

In millions States America North Africa Total

FOR THE YEAR ENDED DECEMBER 31, 2012

Revenues (a) $ 10,379 $ 1,085 $ 7,486 $ 18,950

Production costs (b) 2,963 165 1,061 4,189

Other operating expenses 723 43 224 990

Depreciation, depletion and amortization 2,412 117 1,404 3,933

Taxes other than on income 644 23 — 667

Asset impairments and related items 1,731 — — 1,731

Exploration expenses 230 3 112 345

Pretax income 1,676 734 4,685 7,095

Income tax expense (c) 508 252 2,159 2,919

Results of operations $ 1,168 $ 482 $ 2,526 $ 4,176

FOR THE YEAR ENDED DECEMBER 31, 2011

Revenues (a) $ 9,933 $ 1,113 $ 7,373 $ 18,419

Production costs (b) 2,338 172 918 3,428

Other operating expenses 584 37 217 838

Depreciation, depletion and amortization 1,754 90 1,220 3,064

Taxes other than on income 567 23 — 590

Exploration expenses 200 2 56 258

Pretax income 4,490 789 4,962 10,241

Income tax expense (c) 1,419 270 2,145 3,834

Results of operations $ 3,071 $ 519 $ 2,817 $ 6,407

FOR THE YEAR ENDED DECEMBER 31, 2010

Revenues (a) $ 7,578 $ 1,046 (d) $ 5,621 $ 14,245

Production costs (b) 1,757 167 (d) 698 2,622

Other operating expenses 432 15 208 655

Depreciation, depletion and amortization 1,412 122 1,134 2,668

Taxes other than on income 454 18 — 472

Asset impairments and related items 275 — — 275

Exploration expenses 158 7 97 262

Pretax income 3,090 717 3,484 7,291

Income tax expense (c) 929 227 1,689 2,845

Results of operations $ 2,161 $ 490 (d,e) $ 1,795 $ 4,446

(a) Revenues are net of royalty payments.

(b) Production costs are the costs incurred in lifting the oil and gas to the surface and include gathering, primary processing, field storage and insurance on proved properties, but do not

include DD&A, royalties, income taxes, interest, general and administrative and other expenses.

(c) United States federal income taxes reflect certain expenses related to oil and gas activities allocated for United States income tax purposes only, including allocated interest and corporate

overhead.

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

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

80
RESULTS PER UNIT OF PRODUCTION FOR CONTINUING OPERATIONS

United Latin Middle East/

States America North Africa Total

FOR THE YEAR ENDED DECEMBER 31, 2012

Revenue from each barrel of oil equivalent ($/bbl.) (a,b) $ 61.06 $ 96.30 $ 76.22 $ 67.81

Production costs 17.43 14.64 10.80 14.99

Other operating expenses 4.25 3.82 2.28 3.54

Depreciation, depletion and amortization 14.19 10.38 14.30 14.07

Taxes other than on income 3.79 2.04 — 2.39

Asset impairments and related items 10.18 — — 6.19

Exploration expenses 1.35 0.27 1.14 1.23

Pretax income 9.87 65.15 47.70 25.40

Income tax expense (c) 2.99 22.37 21.98 10.45

Results of operations $ 6.88 $ 42.78 $ 25.72 $ 14.95

FOR THE YEAR ENDED DECEMBER 31, 2011

Revenue from each barrel of oil equivalent ($/bbl.) (a,b) $ 63.56 $ 94.19 $ 74.58 $ 68.99

Production costs 14.96 14.56 9.29 12.84

Other operating expenses 3.74 3.13 2.20 3.14

Depreciation, depletion and amortization 11.22 7.62 12.34 11.48

Taxes other than on income 3.63 1.95 — 2.21

Exploration expenses 1.28 0.17 0.57 0.97

Pretax income 28.73 66.76 50.18 38.35

Income tax expense (c) 9.08 22.85 21.70 14.36

Results of operations $ 19.65 $ 43.91 $ 28.48 $ 23.99

FOR THE YEAR ENDED DECEMBER 31, 2010

Revenue from each barrel of oil equivalent ($/bbl.) (a,b) $ 54.14 $ 73.31 $ 54.49 $ 55.35

Production costs 12.55 11.70 6.77 10.19

Other operating expenses 3.09 1.05 2.02 2.55

Depreciation, depletion and amortization 10.09 8.55 10.99 10.37

Taxes other than on income 3.24 1.26 — 1.83

Asset impairments and related items 1.96 — — 1.07

Exploration expenses 1.13 0.49 0.94 1.02

Pretax income 22.08 50.26 33.77 28.32

Income tax expense (c) 6.64 15.91 16.37 11.05

Results of operations $ 15.44 $ 34.35 (d,e) $ 17.40 $ 17.27

(a) Natural gas volumes have been converted to BOE based on energy content of six thousand cubic feet (Mcf) of gas to one barrel of oil. Barrels of oil equivalence does not necessarily result in

price equivalence. The price of natural gas on a barrel of oil equivalent basis is currently substantially lower than the corresponding price for oil and has been similarly lower over the

recent past. For example, in 2012, the average prices of WTI oil and NYMEX natural gas were $94.21 per barrel and $2.81 per Mcf, respectively, resulting in an oil to gas ratio of over 30.

(b) Revenues are net of royalty payments.

(c) United States federal income taxes reflect certain expenses related to oil and gas activities allocated for United States income tax purposes only, including allocated interest and corporate

overhead.

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

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

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

FLOWS

For purposes of the following disclosures, future cash flows were computed by applying to Occidental's proved oil and gas reserves the

unweighted arithmetic average of the first-day-of-the-month price for each month within the years ended December 31, 2012, 2011 and 2010,

respectively, unless prices were defined by contractual arrangements, and exclude escalations based upon future conditions. The realized prices

used to calculate future cash flows vary by producing area and market conditions. Future operating and capital costs were forecast using the

current cost environment applied to expectations of future operating and development activities. Future income tax expenses were computed by

applying, generally, year-end statutory tax rates (adjusted for permanent differences, tax credits, allowances and foreign income repatriation

considerations) to the estimated net future pre-tax cash flows. The discount was computed by application of a 10-percent discount factor. The

calculations assumed the continuation of existing economic, operating and contractual conditions at December 31, 2012, 2011 and 2010. Such

assumptions, which are required by regulation, have not always proven accurate in the past. Other valid assumptions would give rise to

substantially different results.

81
Standardized Measure of Discounted Future Net Cash Flows

In millions

United Latin Middle East/

States America North Africa Total

AT DECEMBER 31, 2012

Future cash inflows $ 161,821 $ 10,574 $ 48,914 $ 221,309

Future costs

Production costs and other operating expenses (68,780) (3,562) (11,922) (84,264)

Development costs (a) (15,890) (541) (5,539) (21,970)

Future income tax expense (21,387) (2,023) (14,165) (37,575)

Future net cash flows 55,764 4,448 17,288 77,500

Ten percent discount factor (29,745) (1,812) (6,656) (38,213)

Standardized measure of discounted future net cash flows $ 26,019 $ 2,636 $ 10,632 $ 39,287

AT DECEMBER 31, 2011

Future cash inflows $ 171,456 $ 8,494 $ 43,715 $ 223,665

Future costs

Production costs and other operating expenses (69,404) (2,807) (8,926) (81,137)

Development costs (a) (13,660) (689) (3,407) (17,756)

Future income tax expense (26,175) (1,579) (15,374) (43,128)

Future net cash flows 62,217 3,419 16,008 81,644

Ten percent discount factor (32,835) (1,415) (5,127) (39,377)

Standardized measure of discounted future net cash flows $ 29,382 $ 2,004 $ 10,881 $ 42,267

AT DECEMBER 31, 2010

Future cash inflows $ 133,080 $ 6,833 $ 39,156 $ 179,069

Future costs

Production costs and other operating expenses (54,362) (2,828) (9,228) (66,418)

Development costs (a) (9,820) (458) (3,743) (14,021)

Future income tax expense (20,319) (1,036) (12,585) (33,940)

Future net cash flows 48,579 2,511 13,600 64,690

Ten percent discount factor (26,481) (1,044) (4,428) (31,953)

Standardized measure of discounted future net cash flows $ 22,098 $ 1,467 $ 9,172 $ 32,737

(a) Includes asset retirement costs.

Changes in the Standardized Measure of Discounted Future

Net Cash Flows From Proved Reserve Quantities

In millions

For the years ended December 31, 2012 2011 2010

Beginning of year $ 42,267 $ 32,737 $ 23,756

Sales and transfers of oil and gas produced, net of production costs and other operating expenses (14,818) (15,243) (11,698)

Net change in prices received per barrel, net of production costs and other operating expenses (3,005) 20,325 15,507

Extensions, discoveries and improved recovery, net of future production and development costs 5,625 6,152 4,485

Change in estimated future development costs (7,330) (5,668) (2,747)

Revisions of quantity estimates (2,057) (3,518) (626)

Development costs incurred during the period 7,700 5,797 3,101

Accretion of discount 5,203 4,014 2,843

Net change in income taxes 5,045 (4,776) (4,663)

Purchases and sales of reserves in place, net 1,076 3,220 1,871

Changes in production rates and other (419) (773) 908

Net change (2,980) 9,530 8,981

End of year $ 39,287 $ 42,267 $ 32,737

82
Average Sales Prices

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

prices in continuing operations.

United Latin Middle East/

States America (a) North Africa Total

2012

Oil — Average sales price ($/bbl.) $ 93.72 $ 98.35 $ 108.76 $ 99.87

NGLs — Average sales price ($/bbl.) $ 46.07 $ — $ 37.74 $ 45.18

Gas — Average sales price ($/mcf.) $ 2.62 $ 11.85 $ 0.76 $ 2.06

2011

Oil — Average sales price ($/bbl.) $ 92.80 $ 97.16 $ 104.34 $ 97.92

NGLs — Average sales price ($/bbl.) $ 59.10 $ — $ 32.09 $ 55.53

Gas — Average sales price ($/mcf.) $ 4.06 $ 10.11 $ 0.81 $ 3.01

2010

Oil — Average sales price ($/bbl.) $ 73.79 $ 75.29 $ 76.67 $ 75.16

NGLs — Average sales price ($/bbl.) $ 48.86 $ — $ 30.64 $ 45.08

Gas — Average sales price ($/mcf.) $ 4.53 $ 7.73 $ 0.82 $ 3.11

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

Colombian subsidiary.

Net Productive and Dry — Exploratory and Development Wells Completed

The following table sets forth, for each of the three years in the period ended December 31, 2012, Occidental’s net productive and dry

–exploratory and development wells completed.

United Latin Middle East/

States America (a) North Africa Total

2012

Oil — Exploratory 41.0 — 3.3 44.3

Development 1,183.8 51.8 264.6 1,500.2

Gas — Exploratory 3.9 — — 3.9

Development 134.5 1.0 6.5 142.0

Dry — Exploratory 16.5 — 6.1 22.6

Development 31.5 0.4 2.4 34.3

2011

Oil — Exploratory 17.7 1.8 2.6 22.1

Development 834.0 57.9 189.3 1,081.2

Gas — Exploratory 3.2 — 2.5 5.7

Development 143.1 — 1.1 144.2

Dry — Exploratory 13.0 — 1.4 14.4

Development 9.3 — 1.2 10.5

2010

Oil — Exploratory 8.4 0.9 1.8 11.1

Development 406.6 42.3 121.3 570.2

Gas — Exploratory — — 5.0 5.0

Development 93.3 — 4.6 97.9

Dry — Exploratory 17.3 0.8 2.8 20.9

Development 10.0 — 0.4 10.4

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

includes the noncontrolling interest in a Colombian subsidiary.

83
Productive Oil and Gas Wells

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

Wells at

December 31, 2012 (a)

United

States

Latin

America

Middle East/

North Africa Total

Oil — Gross (b) 27,030 (1,839) 1,338 — 3,036 (670) 31,404 (2,509)

Net (c) 22,870 (1,449) 665 — 1,607 (322) 25,142 (1,771)

Gas — Gross (b) 6,743 (424) 30 — 131 (2) 6,904 (426)

Net (c) 5,942 (352) 28 — 69 (2) 6,039 (354)

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

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

(c) The sum of fractional interests.

Participation in Exploratory and Development Wells Being Drilled

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

Wells at

December 31, 2012

United

States

Latin

America

Middle East/

North Africa Total

Exploratory and development wells

— Gross 181 7 56 244

— Net 165 4 25 194

At December 31, 2012, Occidental was participating in 193 pressure-maintenance projects, mostly waterfloods, in the United States, 8 in Latin

America and 33 in the Middle East/North Africa.

Oil and Gas Acreage

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

Thousands of acres at United Latin Middle East/

December 31, 2012 States (a) America North Africa Total

Developed (b)

— Gross (c) 8,373 121 1,233 9,727

— Net (d) 5,012 83 562 5,657

Undeveloped (e)

— Gross (c) 6,208 484 17,058 23,750

— Net (d) 3,042 363 15,102 18,507

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

(b) Acres spaced or assigned to productive wells.

(c) Total acres in which interests are held.

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

(e) Acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas, regardless of whether the acreage contains

proved reserves.

Occidental’s investment in developed and undeveloped acreage comprises numerous concessions, blocks and leases. Work programs are

designed to ensure that the exploration potential of any property is fully evaluated before expiration. In some instances, Occidental may elect to

relinquish acreage in advance of the contractual expiration date if the evaluation process is complete and there is not a business basis for

extension. In cases where additional time may be required to fully evaluate acreage, Occidental has generally been successful in obtaining

extensions. Scheduled lease and concession expirations for undeveloped acreage over the next three years are not expected to have a material

adverse impact on Occidental.

84
Oil, NGLs and Natural Gas Production and Sales Volumes Per Day

The following tables set forth the production and sales volumes of oil, NGLs and natural gas per day for each of the three years in the period

ended December 31, 2012. The differences between the production and sales volumes per day are generally due to the timing of shipments at

Occidental’s international locations where product is loaded onto tankers.

Production per Day 2012 2011 2010

United States

Oil (MBBL)

California 8 8 80 76

Permian 142 134 136

Midcontinent and Other 25 16 7

TOTAL 255 230 219

NGLs (MBBL)

California 17 15 16

Permian 39 38 29

Midcontinent and Other 17 16 7

TOTAL 73 69 52

Natural gas (MMCF)

California 256 260 280

Permian 155 157 199

Midcontinent and Other 410 365 198

TOTAL 821 782 677

Latin America (a)

Oil (MBBL) - Colombia (b) 29 29 37

Natural gas (MMCF) - Bolivia 13 15 16

Middle East/North Africa

Oil (MBBL)

Bahrain 4 4 3

Dolphin 8 9 1 1

Oman 67 67 62

Qatar 71 73 76

Other 36 38 46

TOTAL 186 191 198

NGLs (MBBL)

Dolphin 8 10 13

Other 1 — 1

TOTAL 9 10 14

Natural gas (MMCF)

Bahrain 232 173 169

Dolphin 163 199 236

Oman 57 54 48

TOTAL 452 426 453

Total Production (MBOE) (a,c) 766 733 711

(See footnotes following the Sales Volumes per Day table)

85
Sales Volumes per Day 2012 2011 2010

United States

Oil (MBBL) 255 230 219

NGLs (MBBL) 73 69 52

Natural gas (MMCF) 819 782 677

Latin America (a)

Oil (MBBL) - Colombia (b) 28 29 36

Natural gas (MMCF) - Bolivia 13 15 16

Middle East/North Africa

Oil (MBBL)

Bahrain 4 4 3

Dolphin 8 9 12

Oman 66 69 61

Qatar 71 73 76

Other 36 34 42

TOTAL 185 189 194

NGLs (MBBL)

Dolphin 8 10 12

Other 1 — 1

TOTAL 9 10 13

Natural gas (MMCF) 452 426 453

Total Sales Volumes (MBOE) (a,c) 764 731 705

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

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

(c) Natural gas volumes have been converted to BOE based on energy content of six Mcf of gas to one barrel of oil. Barrels of oil equivalence does not necessarily result in price

equivalence The price of natural gas on a barrel of oil equivalent basis is currently substantially lower than the corresponding price for oil and has been similarly lower over the recent

past. For example, in 2012, the average prices of WTI oil and NYMEX natural gas were $94.21 per barrel and $2.81 per Mcf, respectively, resulting in an oil to gas ratio of over 30.

86
Schedule II – Valuation and Qualifying Accounts Occidental Petroleum Corporation

and Subsidiaries

In millions

Additions

Balance at

Beginning

of Period

Charged to

Costs and

Expenses

Charged to

Other

Accounts Deductions (a)

Balance at

End of

Period

2012

Allowance for doubtful accounts $ 16 $ — $ — $ — $ 16

Environmental $ 360 $ 56 $ — $ (72) $ 344

Litigation, tax and other reserves 198 57 — (26) 229

$ 558 $ 113 $ — $ (98) $ 573 (b)

2011

Allowance for doubtful accounts $ 19 $ — $ — $ (3) $ 16

Environmental $ 366 $ 53 $ 14 $ (73) $ 360

Litigation, tax and other reserves 193 37 — (32) 198

$ 559 $ 90 $ 14 $ (105) $ 558 (b)

2010

Allowance for doubtful accounts $ 30 $ (9) $ — $ (2) $ 19

Environmental $ 403 $ 26 $ 3 $ (66) $ 366

Litigation, tax and other reserves 226 20 6 (59) 193

$ 629 $ 46 $ 9 $ (125) $ 559 (b)

Note: The amounts presented represent continuing operations.

(a) Primarily represents payments.

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

87
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

DISCLOSURE CONTROLS AND PROCEDURES

Occidental's President and Chief Executive Officer and its Executive Vice President and Chief Financial Officer supervised and participated

in Occidental's evaluation of its disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange

Act of 1934 (Exchange Act)) as of the end of the period covered by this report. Based upon that evaluation, Occidental's President and Chief

Executive Officer and Executive Vice President and Chief Financial Officer concluded that Occidental's disclosure controls and procedures were

effective as of December 31, 2012.

There has been no change in Occidental's internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the

Exchange Act) during the fourth quarter of 2012 that has materially affected, or is reasonably likely to materially affect, Occidental's internal

control over financial reporting. Management’s Annual Assessment of and Report on Occidental’s Internal Control over Financial Reporting and

the Report of Independent Registered Public Accounting Firm on Internal Control over Financial Reporting are set forth in Item 8.

ITEM 9B. OTHER INFORMATION

On February 20, 2013, Occidental provided retention payment and severance benefits to Mr. William Albrecht, Vice President and President,

Americas, Oxy Oil and Gas; Mr. James Lienert, Executive Vice President — Business Support; and Mr. Edward Lowe, Vice President and

President, Oxy Oil and Gas - International Production among others. The arrangement for each of these named executive officers provides for a

retention payment in certain circumstances, with his continued employment, equal to twice the executive's then yearly base salary, to be paid

one year after a new Chief Executive Officer commences employment. If the executive is terminated without cause prior to December 31, 2014,

then, subject to providing typical waivers and releases, the executive will receive (i) separation pay at his then current salary for 24 months, (ii)

his target bonus amount for the year of separation and (iii) the same medical and other benefits (other than Notice and Severance Pay) as are

received by employees terminated pursuant to Occidental's Notice and Severance Pay Plan in addition to the retention payment (if not previously

paid).

On February 25, 2013, Occidental extended the term of the Employment Agreement of its Corporate Executive Vice President and Corporate

Secretary, Donald P. de Brier, to December 31, 2014.

The foregoing descriptions of the retention payment and severance benefit arrangement and employment agreement extension are qualified

in their entirety by reference to the Form of Retention Payment and Separation Benefits Attachment and the Amendment to Employment

Agreement, which are attached as Exhibits 10.6 and 10.4, respectively.

Part III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Occidental has adopted a Code of Business Conduct (Code). The Code applies to the President and Chief Executive Officer; Executive Vice

President and Chief Financial Officer; Vice President, Controller and Principal Accounting Officer; and persons performing similar functions (Key

Personnel). The Code also applies to Occidental's directors, its employees and the employees of entities it controls. The Code is posted at

www.oxy.com. Occidental will satisfy any disclosure requirement under Item 5.05 of Form 8-K regarding an amendment to, or waiver from, any

provision of the Code with respect to its Key Personnel or directors by disclosing the nature of that amendment or waiver on its website.

This item incorporates by reference the information regarding Occidental's directors appearing under the caption "Election of Directors -

forepart," and "-Board Committees - Audit Committee," "Security Ownership – Section 16(a) Beneficial Ownership Reporting Compliance," and

"General Information – Nominations for Directors for Term Expiring in 2015" in Occidental's definitive proxy statement, relating to its May 3, 2013,

Annual Meeting of Stockholders (2013 Proxy Statement). The list of Occidental's executive officers and related information under "Executive

Officers" set forth in Part I of this report is incorporated by reference herein.

ITEM 11. EXECUTIVE COMPENSATION

This item incorporates by reference the information appearing under the captions "Compensation Discussion and Analysis," (except

"Succession Planning"), "Executive Compensation Tables" and "Director Compensation" in the 2013 Proxy Statement. Pursuant to the rules and

regulations under the Exchange Act, the information under the caption "Compensation Discussion and Analysis - Compensation Committee

Report" shall not be deemed to be "soliciting material," or to be "filed" with the SEC, or subject to Regulation 14A or 14C under the Exchange Act or

to the liabilities of Section 18 of the Exchange Act, nor shall it be deemed incorporated by reference into any filing under the Securities Act of 1933.

88
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

This item incorporates by reference the information with respect to security ownership appearing under the caption "Security Ownership –

Certain Beneficial Owners and Management" in the 2013 Proxy Statement. See also the information under "Securities Authorized for Issuance

Under Equity Compensation Plans" in Part II, Item 5 of this report.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

This item incorporates by reference the information appearing under the caption "Corporate Governance – Board of Directors and its

Committees – Independence", and " – Related Party Transactions" in the 2013 Proxy Statement.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

This item incorporates by reference the information with respect to accountant fees and services appearing under the captions "Ratification of

Independent Auditors – Audit and Other Fees" in the 2013 Proxy Statement.

Part IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

The agreements included as exhibits to this report are included to provide information about their terms and not to provide any other factual or

disclosure information about Occidental or the other parties to the agreements. The agreements contain representations and warranties by each of

the parties to the applicable agreement that were made solely for the benefit of the other agreement parties and:

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

be inaccurate;

• have been qualified by disclosures that were made to the other party in connection with the negotiation of the applicable agreement, which

disclosures are not necessarily reflected in the agreement;

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

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

more recent developments.

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

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

(a) (3). Exhibits

3.(i)* Restated Certificate of Incorporation of Occidental, dated November 12, 1999 (filed as Exhibit 3.(i) to the Annual Report on Form 10-K of

Occidental for the fiscal year ended December 31, 1999, File No. 1-9210).

3.(i)(a)* Certificate of Change of Location of Registered Office and of Registered Agent, dated July 6, 2001 (filed as Exhibit 3.1(i) to the Registration

Statement on Form S-3 of Occidental, File No. 333-82246).

3.(i)(b)* Certificate of Amendment of Restated Certificate of Incorporation of Occidental Petroleum Corporation, dated May 5, 2006 (filed as Exhibit 3.(i)(b) to

the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2006, File No. 1-9210).

3.(i)(c)* Certificate of Amendment of Restated Certificate of Incorporation of Occidental Petroleum Corporation, dated May 1, 2009 (filed as Exhibit 3.(i)(c) to

the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended June 30, 2009, File No. 1-9210).

3.(ii)* Bylaws of Occidental, as amended through May 5, 2011 (filed as Exhibit 3.(ii) to the Current Report on Form 8-K of Occidental dated May 5, 2011

(date of earliest event reported), filed May 6, 2011, File No. 1-9210).

4.1* Indenture, dated as of August 18, 2011, between Occidental Petroleum and The Bank of New York Mellon Trust Company, N.A. (filed as Exhibit

4.1 to the Current Report on Form 8-K of Occidental dated August 15, 2011 (date of earliest event reported), File No. 1-9210).

4.2* Indenture (Senior Debt Securities), dated as of April 1, 1998, between Occidental and The Bank of New York, as Trustee (filed as Exhibit 4 to the

Registration Statement on Form S-3 of Occidental, File No. 333-52053).

Instruments defining the rights of holders of other long-term debt of Occidental and its subsidiaries are not being filed since the total amount of securities

authorized under each of such instruments does not exceed 10 percent of the total assets of Occidental and its subsidiaries on a consolidated basis. Occidental

agrees to furnish a copy of any such instrument to the Commission upon request.

All of the Exhibits numbered 10.1 to 10.68 are management contracts and compensatory plans required to be identified specifically as responsive to Item

601(b)(10)(iii)(A) of Regulation S-K pursuant to Item 15(b) of Form 10-K.

10.1* Amended and Restated Employment Agreement, dated as of October 9, 2008, between Occidental and Dr. Ray R. Irani (filed as Exhibit 10.1 to the

Quarterly Report on Form 10-Q of Occidental for the quarterly period ended September 30, 2008, File No. 1-9210).

10.2* Employment Agreement, dated January 28, 2010, between Occidental and Stephen I. Chazen (filed as Exhibit 10.1 to the Current Report on Form

8-K of Occidental dated January 28, 2010, File No. 1-9210).

10.3* Amended and Restated Employment Agreement, dated October 9, 2008, between Occidental and Donald P. de Brier (filed as Exhibit 10.3 to the

Quarterly Report on Form 10-Q of Occidental for the quarterly period ended September 30, 2008, File No. 1-9210).

____________________________

* Incorporated herein by reference

89
10.4 Amendment to Employment Agreement, dated February 25, 2013, between Occidental and Donald P. de Brier.

10.5* Agreement with Chief Financial Officer (filed as Exhibit 10.7 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended June

30, 2012, File No. 1-9210).

10.6 Retention Payment and Separation Benefits Attachment.

10.7* Form of Indemnification Agreement between Occidental and each of its directors and certain executive officers (filed as Exhibit B to the Proxy

Statement of Occidental for its May 21, 1987, Annual Meeting of Stockholders, File No. 1-9210).

10.8* Occidental Petroleum Corporation Split Dollar Life Insurance Program and Related Documents (filed as Exhibit 10.2 to the Quarterly Report on

Form 10-Q of Occidental for the quarterly period ended September 30, 1994, File No. 1-9210).

10.9* Split Dollar Life Insurance Agreement, dated January 24, 2002, by and between Occidental and Donald P. de Brier (filed as Exhibit 10.1 to the

Quarterly Report on Form 10-Q of Occidental for the quarterly period ended March 31, 2002, File No. 1-9210).

10.10* Occidental Petroleum Insured Medical Plan, as amended and restated effective April 29, 1994, amending and restating the Occidental Petroleum

Corporation Executive Medical Plan (as amended and restated effective April 1, 1993) (filed as Exhibit 10 to the Quarterly Report on Form 10-Q of

Occidental for the quarterly period ending March 31, 1994, File No. 1-9210).

10.11* Form of Occidental Petroleum Corporation Modified Deferred Compensation Plan (Effective December 31, 2006, Amended and Restated Effective

November 1, 2008) (filed as Exhibit 10.4 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended September 30, 2008,

File No. 1-9210).

10.12* Form of Occidental Petroleum Corporation Amendment to Senior Executive Supplemental Life Insurance Plan (Effective as of January 1, 1986,

Amended and Restated Effective as of January 1, 1996) (filed as Exhibit 10.5 to the Quarterly Report on Form 10-Q of Occidental for the quarterly

period ended September 30, 2008, File No. 1-9210).

10.13* Form of Occidental Petroleum Corporation Amendment to Senior Executive Survivor Benefit Plan (Effective as of January 1, 1986, Amended and

Restated Effective as of January 1, 1996) (filed as Exhibit 10.6 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended

September 30, 2008, File No. 1-9210).

10.14* Form of Occidental Petroleum Corporation Supplemental Retirement Plan II (Effective as of January 1, 2005, Amended and Restated as of

November 1, 2008) (filed as Exhibit 10.7 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended September 30, 2008,

File No. 1-9210).

10.15* Amendment Number 1 to the Occidental Petroleum Corporation Supplemental Retirement Plan II (Effective As Of January 1, 2005, Amended And

Restated As Of November 1, 2008) (filed as Exhibit 10.16 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31,

2009, File No. 1-9210).

10.16* Amendment Number 2 to the Occidental Petroleum Corporation Supplemental Retirement Plan II (Effective As Of January 1, 2005, Amended And

Restated As Of November 1, 2008) (filed as Exhibit 10.17 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31,

2009, File No. 1-9210).

10.17* Amendment Number 3 to the Occidental Petroleum Corporation Supplemental Retirement Plan II (Effective As Of January 1, 2005, Amended and

Restated as of November 1, 2008) (filed as Exhibit 10.18 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31,

2011, File No. 1-9210).

10.18* Amendment Number 4 to the Occidental Petroleum Corporation Supplemental Retirement Plan II (Effective As Of January 1, 2005, Amended and

Restated as of November 1, 2008) (filed as Exhibit 10.19 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31,

2011, File No. 1-9210).

10.19 Amendment Number 5 to the Occidental Petroleum Corporation Supplemental Retirement Plan II (Effective as of January 1, 2005, Amended and

Restated as of November 1, 2008).

10.20* Occidental Petroleum Corporation 2001 Incentive Compensation Plan (as amended through September 12, 2002) (filed as Exhibit 10.2 to the

Quarterly Report on Form 10-Q of Occidental for the quarterly period ended September 30, 2002, File No. 1-9210).

10.21* Form of Incentive Stock Option Agreement under Occidental Petroleum Corporation 2001 Incentive Compensation Plan (July 2002 version) (filed

as Exhibit 10.4 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended September 30, 2002, File No. 1-9210).

10.22* Form of Nonqualified Stock Option Agreement under Occidental Petroleum Corporation 2001 Incentive Compensation Plan (July 2002 version)

(filed as Exhibit 10.5 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended September 30, 2002, File No. 1-9210).

10.23* Terms and Conditions for Incentive Stock Option Award under Occidental Petroleum Corporation 2001 Incentive Compensation Plan (July 2003

version) (filed as Exhibit 10.3 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended June 30, 2003, File No. 1-9210).

10.24* Terms and Conditions for Nonqualified Stock Option Award under Occidental Petroleum Corporation 2001 Incentive Compensation Plan (July 2003

version) (filed as Exhibit 10.4 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended June 30, 2003, File No. 1-9210).

10.25* Terms and Conditions of Stock Appreciation Rights Award under Occidental Petroleum Corporation 2001 Incentive Compensation Plan (filed as

Exhibit 10.3 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended June 30, 2004, File No. 1-9210).

10.26* Occidental Petroleum Corporation 2005 Long-Term Incentive Plan, as amended through October 13, 2010 (filed as Exhibit 10.1 to the Current

Report on Form 8-K of Occidental dated October 13, 2010 (date of earliest event reported), filed October 14, 2010, File No. 1-9210).

10.27* Terms and Conditions of Stock Appreciation Rights Award under Occidental Petroleum Corporation 2005 Long-Term Incentive Plan (filed as

Exhibit 10.12 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended June 30, 2005, File No. 1-9210).

10.28* Agreement to Amend Outstanding Option Awards, dated October 26, 2005 (filed as Exhibit 10.2 to the Quarterly Report on Form 10-Q of Occidental

for the quarterly period ended September 30, 2005, File No. 1-9210).

10.29* Terms and Conditions of Stock Appreciation Rights (SARs) under Occidental Petroleum Corporation 2005 Long-Term Incentive Plan (July 2006

version) (filed as Exhibit 10.4 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended June 30, 2006, File No. 1-9210).

10.30* Form of Occidental Petroleum Corporation 2005 Deferred Stock Program (Restatement Effective as of November 1, 2008) (filed as Exhibit 10.8 to

the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended September 30, 2008, File No. 1-9210).

____________________________

* Incorporated herein by reference

90
10.31* Occidental Petroleum Corporation Executive Incentive Compensation Plan (filed as Exhibit 10.69 to the Annual Report on Form 10-K of Occidental

for the fiscal year ended December 31, 2005, File No. 1-9210).

10.32* Description of financial counseling program (filed as Exhibit 10.50 to the Annual Report on Form 10-K of Occidental for the fiscal year ended

December 31, 2003, File No. 1-9210).

10.33* Description of group excess liability insurance program (filed as Exhibit 10.51 to the Annual Report on Form 10-K of Occidental for the fiscal year

ended December 31, 2003, File No. 1-9210).

10.34* Executive Stock Ownership Guidelines (filed as Exhibit 10.1 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended

March 31, 2005, File No. 1-9210).

10.35* Form of Restricted Stock Award for Non-Employee Directors under Occidental Petroleum Corporation 2005 Long-Term Incentive Plan (filed as

Exhibit 10.1 to the Current Report on Form 8-K of Occidental dated February 16, 2006 (date of earliest event reported), filed February 22, 2006,

File No. 1-9210).

10.36* Amendment to Form of Restricted Stock Award for Non-Employee Directors under Occidental Petroleum Corporation 2005 Long-Term Incentive

Plan (filed as Exhibit 10.3 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended September 30, 2007, File No. 1-9210).

10.37* Form of Restricted Stock Award for Non-Employee Directors under Occidental Petroleum Corporation 2005 Long-Term Incentive Plan (2007

version) (filed as Exhibit 10.4 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended September 30, 2007, File No. 1-

9210).

10.38* Director Retainer and Attendance Fees (filed as Exhibit 10.2 to the Current Report on Form 8-K of Occidental dated February 16, 2006 (date of

earliest event reported), filed February 22, 2006, File No. 1-9210).

10.39* Description of Automatic Grant of Directors’ Restricted Stock Awards Pursuant to the Terms of the Occidental Petroleum Corporation 2005 LongTerm Incentive Plan (filed as Exhibit 10.2 to the Quarterly Report on Form 10-Q of Occidental dated for the fiscal quarter ended June 30, 2010,

File No. 1-9210).

10.40* Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Occidental Oil And Gas Corporation Return On Assets Incentive Award

Agreement (Cash-Based, Cash-Settled Award) (filed as Exhibit 10.5 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended

June 30, 2007, File No. 1-9210).

10.41* Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Occidental Chemical Corporation Return On Assets Incentive Award Agreement

(Cash-Based, Cash-Settled Award) (filed as Exhibit 10.6 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended June 30,

2007, File No. 1-9210).

10.42* Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Total Shareholder Return Incentive Award Agreement (Equity-based, Equity and

Cash-settled Award) (filed as Exhibit 10.2 to the Current Report On Form 8-K of Occidental dated July 16, 2008 (date of earliest event reported), File

No. 1-9210).

10.43* Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Occidental Oil and Gas Corporation Return on Assets Incentive Award

Agreement (Cash-based, Cash-settled Award) (filed as Exhibit 10.5 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended

June 30, 2008, File No. 1-9210).

10.44* Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Occidental Chemical Corporation Return on Assets Incentive Award Agreement

(Cash-based, Cash-settled Award) (filed as Exhibit 10.6 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended June 30,

2008, File No. 1-9210).

10.45* Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Return on Equity Incentive Award Agreement (Cash-based, Cash-settled Award)

(filed as Exhibit 10.1 to the Current Report on Form 8-K of Occidental dated July 15, 2009 (Date of Earliest Event Reported), File No. 1-9210).

10.46* Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Total Shareholder Return Incentive Award Agreement (Equity-based, Equity and

Cash-settled Award) (filed as Exhibit 10.2 to the Current Report on Form 8-K of Occidental dated July 15, 2009 (Date of Earliest Event Reported),

File No. 1-9210).

10.47* Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Occidental Chemical Corporation Return on Assets Incentive Award Agreement

(Cash-based, Cash-settled Award) (filed as Exhibit 10.3 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended June 30,

2009, File No. 1-9210).

10.48* Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Occidental Oil and Gas Corporation Return on Assets Incentive Award

Agreement (Cash-based, Cash-settled Award) (filed as Exhibit 10.4 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended

June 30, 2009, File No. 1-9210).

10.49* Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Long-Term Incentive Award Terms and Conditions (Equity-based, Cash-settled

Award) (filed as Exhibit 10.5 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended June 30, 2009, File No. 1-9210).

10.50* Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Long-Term Incentive Award Terms and Conditions (Equity-based, Cash-settled

Award) (alternate – CV) (filed as Exhibit 10.6 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended June 30, 2009, File

No. 1-9210).

10.51* Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Restricted Stock Incentive Award Terms and Conditions (filed as Exhibit 10.2 to

the Current Report on Form 8-K of Occidental dated October 13, 2010 (date of earliest event reported), filed October 14, 2010, File No. 1-9210).

10.52* Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Total Shareholder Return Incentive Award Terms and Conditions (Equity-based,

Equity and Cash-settled Award) (filed as Exhibit 10.3 to the Current Report on Form 8-K of Occidental dated October 13, 2010 (date of earliest event

reported), filed October 14, 2010, File No. 1-9210).

10.53* Form of Amendment to 2008 Return On Equity Incentive Award Grant Agreement (filed as Exhibit 10.1 to the Current Report on Form 8-K of

Occidental dated July 13, 2011 (date of earliest event reported), filed July 18, 2011, File No. 1-9210).

10.54* Form of Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Total Shareholder Return Incentive Award Terms and Conditions

(Equity-based, Equity and Cash-settled Award) (filed as Exhibit 10.2 to the Current Report on Form 8-K of Occidental dated July 13, 2011 (date of

earliest event reported), filed July 18, 2011, File No. 1-9210).

____________________________

* Incorporated herein by reference

91
10.55* Form of Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Restricted Stock Incentive Award Terms and Conditions (filed as Exhibit

10.3 to the Current Report on Form 8-K of Occidental dated July 13, 2011 (date of earliest event reported), filed July 18, 2011, File No. 1-9210).

10.56* Form of Acknowledgment Letter (filed as Exhibit 10.4 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended June 30,

2011, File No. 1-9210).

10.57* Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Long-Term Incentive Award Terms and Conditions (Cash-Based, Cash-Settled

Award) (filed as Exhibit 10.5 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended June 30, 2011, File No. 1-9210).

10.58* Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Occidental Chemical Corporation Return on Assets Incentive Award Terms and

Conditions (Cash-Based, Cash- Settled Award) (filed as Exhibit 10.6 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter

ended June 30, 2011, File No. 1-9210).

10.59* Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Occidental Oil and Gas Corporation Return on Assets Incentive Award Terms

and Conditions (Cash-Based, Cash-Settled Award) (filed as Exhibit 10.7 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter

ended June 30, 2011, File No. 1-9210).

10.60* Form of Restricted Stock Award for Non-Employee Directors under Occidental Petroleum Corporation 2005 Long-Term Incentive Plan (filed as

Exhibit 10.1 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended March 31, 2012, File No. 1-9210).

10.61* Form of Restricted Stock Unit Award for Non-Employee Directors under Occidental Petroleum Corporation 2005 Long-Term Incentive Plan (filed

as Exhibit 10.2 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended March 31, 2012, File No. 1-9210).

10.62* Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Restricted Stock Award Terms and Conditions. (filed as Exhibit 10.3 to the

Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended March 31, 2012, File No. 1-9210).

10.63* Form of Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Total Shareholder Return Incentive Award Terms And Conditions

(Equity-based and Equity-settled Award) (filed as Exhibit 10.2 to Occidental's Current Report on Form 8-K dated July 11, 2012 (date of earliest

event reported), filed July 13, 2012, File No. 1-9210).

10.64* Form of Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Restricted Stock Incentive Award Terms and Conditions (filed as Exhibit

10.3 to Occidental's Current Report on Form 8-K dated July 11, 2012 (date of earliest event reported), filed July 13, 2012, File No. 1-9210).

10.65* Form of Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Long-Term Incentive Award Terms and Conditions (Cash-Based, Equity

And Cash-Settled Award) (filed as Exhibit 10.3 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended June 30, 2012, File

No. 1-9210).

10.66* Form of Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Occidental Chemical Corporation Return on Assets Incentive Award

Terms and Conditions (Cash-Based, Cash-Settled Award) (filed as Exhibit 10.4 to the Quarterly Report on Form 10-Q of Occidental for the fiscal

quarter ended June 30, 2012, File No. 1-9210).

10.67* Form of Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Occidental Oil and Gas Corporation Return on Assets Incentive Award

Terms and Conditions (Cash-Based, Cash-Settled Award) (filed as Exhibit 10.5 to the Quarterly Report on Form 10-Q of Occidental for the fiscal

quarter ended June 30, 2012, File No. 1-9210).

10.68* Form of Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Common Stock and Sign-On Bonus and Other Award Agreement (filed

as Exhibit 10.6 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended June 30, 2012, File No. 1-9210).

12 Statement regarding computation of total enterprise ratios of earnings to fixed charges for each of the five years in the period ended December 31,

2012.

21 List of subsidiaries of Occidental at December 31, 2012.

23.1 Consent of Independent Registered Public Accounting Firm.

23.2 Consent of Independent Petroleum Engineers.

31.1 Certification of CEO Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2 Certification of CFO Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1 Certifications of CEO and CFO Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

99.1 Ryder Scott Company Process Review of the Estimated Future Reserves and Income Attributable to Certain Fee, Leasehold and Royalty Interests

and Certain Economic Interests Derived Through Certain Production Sharing Contracts as of December 31, 2012.

101.INS XBRL Instance Document.

101.SCH XBRL Taxonomy Extension Schema Document.

101.CAL XBRL Taxonomy Extension Calculation Linkbase Document.

101.LAB XBRL Taxonomy Extension Label Linkbase Document.

101.PRE XBRL Taxonomy Extension Presentation Linkbase Document.

101.DEF XBRL Taxonomy Extension Definition Linkbase Document.

____________________________

* Incorporated herein by reference

92
SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed

on its behalf by the undersigned, thereunto duly authorized.

OCCIDENTAL PETROLEUM CORPORATION

February 26, 2013 By: /s/ Stephen I. Chazen

Stephen I. Chazen

President

and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the

registrant and in the capacities and on the dates indicated.

Title Date

/s/Stephen I. Chazen President,

Stephen I. Chazen Chief Executive Officer and Director February 26, 2013

/s/ Cynthia L. Walker Executive Vice President and

Cynthia L. Walker Chief Financial Officer February 26, 2013

/s/ Roy Pineci Vice President, Controller and

Roy Pineci Principal Accounting Officer February 26, 2013

/s/ Spencer Abraham

Spencer Abraham Director February 26, 2013

/s/ Howard I. Atkins

Howard I. Atkins Director February 26, 2013

/s/ Edward P. Djerejian

Edward P. Djerejian Director February 26, 2013

/s/ John E. Feick

John E. Feick Director February 26, 2013

/s/ Margaret M. Foran

Margaret M. Foran Director February 26, 2013

/s/ Carlos M. Gutierrez

Carlos M. Gutierrez Director February 26, 2013

 /s/ Ray R. Irani Executive Chairman

Dr. Ray R. Irani of the Board of Directors February 26, 2013

93
Title Date

/s/Avedick B. Poladian

Avedick B. Poladian Director February 26, 2013

/s/ Aziz D. Syriani

Aziz D. Syriani Director February 26, 2013

/s/ Rosemary Tomich

Rosemary Tomich Director February 26, 2013

94
EXHIBITS FILED WITH THIS REPORT

10.4 Amendment to Employment Agreement, dated February 25, 2013, between Occidental and Donald P. de Brier.

10.6 Retention Payment and Separation Benefits Attachment.

10.19 Amendment Number 5 to the Occidental Petroleum Corporation Supplemental Retirement Plan II (Effective as of January 1, 2005,

Amended and Restated as of November 1, 2008).

1 2 Statement regarding computation of total enterprise ratios of earnings to fixed charges for each of the five years in the period ended

December 31, 2012.

2 1 List of subsidiaries of Occidental at December 31, 2012 .

23.1 Consent of Independent Registered Public Accounting Firm.

23.2 Consent of Independent Petroleum Engineers.

31.1 Certification of CEO Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2 Certification of CFO Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1 Certifications of CEO and CFO Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

99.1 Ryder Scott Company Process Review of the Estimated Future Reserves and Income Attributable to Certain Fee, Leasehold and

Royalty Interests and Certain Economic Interests Derived Through Certain Production Sharing Contracts as of December 31, 2012 .

101.INS XBRL Instance Document.

101.SCH XBRL Taxonomy Extension Schema Document.

101.CAL XBRL Taxonomy Extension Calculation Linkbase Document.

101.LAB XBRL Taxonomy Extension Label Linkbase Document.

101.PRE XBRL Taxonomy Extension Presentation Linkbase Document.

101.DEF XBRL Taxonomy Extension Definition Linkbase Document.

9 5
EXHIBIT 10.4

AMENDMENT

T O

EMPLOYMENT AGREEMENT

This Amendment to Employment Agreement (this “ Amendment”) is made as of the 25th day of February, 2013 by and

between Occidental Petroleum Corporation, a Delaware corporation (hereinafter referred to as “ Employer”), and Donald P. de Brier

(hereinafter referred to as “Employee”).

WITNESSETH

WHEREAS, Employee has been rendering services to Employer, most recently pursuant to a written agreement between

Employee and Employer dated October 9, 2008 (the “ Agreement”); and

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

NOW, THEREFORE, in consideration of the mutual covenants and agreements herein, Employer and Employee hereby agree

to amend the Agreement as follows:

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

Secretary.

2. In accordance with the Paragraphs 2 and 9 of the Agreement, the term of employment under the Agreement is extended to

midnight December 31, 2014, unless terminated prior thereto in accordance with the provisions of the Agreement, or unless extended

by mutual agreement in accordance with Paragraphs 2 and 9 of the Agreement.

3. As amended by this Amendment, the Agreement shall continue in full force and effect for the extended term described in

the preceding paragraph. The provisions of Paragraphs 9 through 14 of the Agreement shall apply to this Amendment, but with all

references to the Agreement being deemed to refer to this Amendment.

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

/s/ DONALD P. DE BRIER

Donald P. de Brier

OCCIDENTAL PETROLEUM CORPORATION

By: /s/ MARTIN A. COZYN

Martin A. Cozyn,

Executive Vice President - Human Resources
EXHIBIT 10.6

RETENTION PAYMENT AND SEPARATION BENEFITS

ATTACHMENT

a. Retention Payment. Oxy will pay you an amount equal to 2 times your then yearly base salary in one lump sum cash

payment at the date that is one year after the new CEO commences employment.

b. Separation Benefits. If, prior to December 31, 2014, Oxy terminates you without cause, then, subject to your timely

execution of waivers and releases of the type required by Oxy's Notice and Severance Pay Plan, you will receive in

addition to your Retention Payment, at your separation date or the time otherwise provided below:

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

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

3. The same medical and other benefits (other than Notice and Severance Pay) as are received by employees

terminated pursuant to Oxy's Notice and Severance Pay Plan.

Payments of your separation pay under Paragraph b.1 shall be made monthly beginning the month after separation;

provided, however, that to the extent required by Section 409A of the U.S. Internal Revenue Code and the regulations

promulgated thereunder (“Section 409A”), the payment of certain amounts will be delayed until the seventh month that

begins after your separation date. Payment under Paragraph b.2 will be made as soon as practicable after the date you

become entitled to the payment under this provision or at the time provided for in any underlying compensation

arrangement or plan if required for compliance with Section 409A. Although not guaranteed by the Company, payments

under this attachment are intended to be exempt or compliant with Section 409A, and the attachment will be interpreted

accordingly. Payments under this attachment will be subject to all applicable tax and tax-related items withholding

requirements. In addition, the separation payments to be paid pursuant to this attachment will not exceed the amount

permitted under Oxy's Golden Parachute Policy unless such separation payments are approved by a vote of Oxy's

stockholders.

c. Other Benefits. The foregoing is not intended to be a comprehensive listing of the benefits to which you may be entitled at

the time of your separation, including your rights under any outstanding incentive awards. In addition, the Executive

Compensation and Human Resources Committee may, in its sole discretion, decide to provide additional separation

benefits.

Ret&SepBen - NEO
EXHIBIT 10.19

AMENDMENT NUMBER 5

TO THE

OCCIDENTAL PETROLEUM CORPORATION

SUPPLEMENTAL RETIREMENT PLAN II

Effective as of January 1, 2005

Amended and Restated as of November 1, 2008

The Occidental Petroleum Corporation Supplemental Retirement Plan II (Effective as of January 1, 2005, Amended and Restated as of

November 1, 2008) (the “Plan”) is hereby amended as of January 1, 2013, as follows:

1. The following new definition of “Secondary Threshold Amount” is added as subsection 2.1(x) and all

subsequent subsections under section 2.1 and any cross-references in the Plan to such subsections are renumbered accordingly:

(x) “Secondary Threshold Amount” means the amount determined by the Company and communicated to

Employees in advance of the Plan Year as the level of annualized Base Pay of Record plus Annual Bonus

awarded in the Plan Year, less any portion of such Annual Bonus deferred under the Deferred Compensation

Plan, each determined as of May 1 of the Plan Year, at which the sum of all contributions made by and on behalf

of an Employee under the Savings Plan and Retirement Plan would exceed the dollar limit in effect for the

Plan Year under Code section 415(c)(1)(A), based on (1) the maximum contribution rates for the most highly

compensated employees and maximum employer matching contribution rates under the Savings Plan and (2)

the employer contribution rates for Employees who have attained age 35 as of the last day of the Plan Year

under the Retirement Plan.

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

amended to read as follows:

(bb) “Threshold Amount” means the amount determined by the Company and communicated to Employees in

advance of the Plan Year as the level of annualized Base Pay of Record at which the sum of all contributions

made by and on behalf of an Employee under the Savings Plan and Retirement Plan would exceed the dollar

limit in effect for the Plan Year under Code section 415(c)(1)(A), based on (1) an assumed level of Annual

Bonus for a particular level of Base Pay of Record determined by the Company in advance of the Plan Year, (2)

the maximum contribution rates for the most highly compensated employees and maximum employer

matching contribution rates under the Savings Plan, and (3) the employer contribution rate for Employees who

have attained age 35 as of the last day of the Plan Year under the Retirement Plan.
3. Subsection (a) in section 3.1 is amended to read as follows:

(a) The first day on which the Employee's annualized Base Pay of Record exceeds the Threshold Amount or, with

respect to an Employee whose annualized Base Pay of Record does not exceed the Threshold Amount, May 1st

of a Plan Year if the sum of the Employee's annualized Base Pay of Record as of May 1 of the Plan Year and

Annual Bonus awarded during the Plan Year, less any portion of such Annual Bonus deferred under the

Deferred Compensation Plan, exceeds the Secondary Threshold Amount.

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

paragraph (3).

(2) An Employee:

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

(B) The sum of whose annualized Base Pay of Record as of May 1 of the Plan Year and Annual Bonus

awarded during the Plan Year, less any portion of such Annual Bonus deferred under the Deferred

Compensation Plan, exceeds the Secondary Threshold Amount applicable to the Employee for the Plan

Year.

Whether an Employee meets the requirements of this paragraph (2) shall be determined as of May 1 st of each

Plan Year by the Company. An Employee who meets such requirements shall be eligible for the allocation

specified in subsection (b) beginning as of May 1 st of the Plan Year (or with respect to a newly eligible

Employee, once the Employee's participation in the Plan has commenced pursuant to Section 3.1). Until such

determination is made during the Plan Year (and, with respect to a newly eligible Employee, the Employee's

participation in the Plan has commenced pursuant to Section 3.1), an Employee shall not be treated as actively

participating in this Plan with respect to a Plan Year by reason of this paragraph (2) and, unless otherwise eligible

under paragraph (1), shall not be entitled to the allocations specified in subsection (b) for the Plan Year.

5. Except as amended above, the terms of the Plan as in effect prior to this amendment shall continue unchanged.
EXHIBIT 12

OCCIDENTAL PETROLEUM CORPORATION AND SUBSIDIARIES

COMPUTATION OF TOTAL ENTERPRISE RATIOS OF EARNINGS TO FIXED CHARGES

(Amounts in millions, except ratios)

For the years ended December 31, 2012 2011 2010 2009 2008

Income from continuing operations $ 4,635 (a) $ 6,640 $ 4,641 $ 3,202 $ 7,299

Subtract:

Net income attributable to noncontrolling interest — — (72) (51) (116)

Adjusted income from equity investments (b) 163 (33) (60) (88) (84)

4,798 6,607 4,509 3,063 7,099

Add:

Provision for taxes on income (other than foreign oil and gas

taxes) 708 1,795 1,099 695 2,213

Interest and debt expense 130 135 (c) 116 140 133

Portion of lease rentals representative of the interest factor 59 60 57 57 58

897 1,990 1,272 892 2,404

Earnings before fixed charges $ 5,695 $ 8,597 $ 5,781 $ 3,955 $ 9,503

Fixed charges:

Interest and debt expense including capitalized interest $ 254 $ 221 (c) $ 203 $ 218 $ 201

Portion of lease rentals representative of the interest factor 59 60 57 57 58

Total fixed charges $ 313 $ 281 $ 260 $ 275 $ 259

Ratio of earnings to fixed charges 18.19 30.59 22.23 14.38 36.69

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

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

(b) Represent adjustments to arrive at distributed income of equity investees.

(c) Excludes a pre-tax charge of $163 million for the early redemption of debt.
EXHIBIT 21

LIST OF SUBSIDIARIES

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

aggregate constitute a significant subsidiary.

Name Jurisdiction of Formation

Armand Products Company Delaware

Bravo Pipeline Company Delaware

BridgeTex Pipeline Company, LLC Delaware

Carbocloro S.A. Industrias Quimicas Brazil

Centurion Pipeline GP, Inc. Delaware

Centurion Pipeline L.P. Delaware

Centurion Pipeline LP, Inc. Delaware

D.S. Ventures, Inc. Texas

DMM Financial LLC Delaware

EHPP Holdings Inc. Delaware

Elk Hills Power, LLC Delaware

Glenn Springs Holdings, Inc. Delaware

ICC Resin Technology, Inc. Delaware

INDSPEC Chemical Corporation Delaware

INDSPEC Holding Corporation Delaware

Ingleside Cogeneration GP 2, Inc. Delaware

Ingleside Cogeneration GP, Inc. Delaware

Ingleside Cogeneration Limited Partnership Delaware

Joslyn Partnership Alberta, Canada

Laguna Petroleum Corporation Texas

Lomita Gasoline Company, Inc. California

Marico Exploration, Inc. New Mexico

MC2 Technologies Inc. Delaware

Miller Springs Remediation Management, Inc. Delaware

Moncrief Minerals Partnership, L.P. Texas

Monument Production, Inc. California

MTD Pipeline LLC Delaware

Natural Gas Odorizing, Inc. Oklahoma

NGL Ventures LLC Delaware

Occidental Al Hosn, LLC Delaware

Occidental (Bermuda) Ltd. Bermuda

Occidental (East Shabwa), LLC Nevis

Occidental Andina, LLC Delaware

Occidental Canada Holdings Ltd. Nova Scotia

Occidental Chemical Chile Limitada Chile

Occidental Chemical Corporation New York

Occidental Chemical de Mexico, S.A. de C.V. Mexico

Occidental Chemical Holding Corporation California

Occidental Chemical International, Inc. California

Occidental Chemical Nevis, Inc. Nevis

Occidental Chile Investments, LLC Delaware

Occidental Chile Minority Holder, LLC Delaware
EXHIBIT 21 (cont'd)

Name Jurisdiction of Formation

Occidental Colombia (Series G) Ltd. Bermuda

Occidental Colombia (Series J) Ltd. Bermuda

Occidental Crude Sales, Inc. (International) Delaware

Occidental Crude Sales, LLC (South America) Delaware

Occidental de Colombia, LLC Delaware

Occidental del Ecuador, Inc. Nevis

Occidental Dolphin Holdings Ltd. Bermuda

Occidental Energy Marketing, Inc. Delaware

Occidental Energy Transportation LLC Delaware

Occidental Energy Ventures Corp. Delaware

Occidental Exploration and Production Company California

Occidental International (Libya), Inc. Delaware

Occidental International Exploration and Production Company California

Occidental International Holdings Ltd. Bermuda

Occidental International Oil and Gas Ltd. Bermuda

Occidental International Services, Inc. Delaware

Occidental Joslyn GP 1 Co. Nova Scotia

Occidental Joslyn GP 2 Co. Nova Scotia

Occidental Karawan Holding Ltd. Bermuda

Occidental Karawan, LLC Delaware

Occidental Latin America Holdings, Inc. Delaware

Occidental Libya Oil & Gas B.V. The Netherlands

Occidental Middle East Development Company Delaware

Occidental Midstream Projects Ltd. Bermuda

Occidental Mukhaizna, LLC Delaware

Occidental of Abu Dhabi (Bab) Ltd. Bermuda

Occidental of Abu Dhabi Ltd. Bermuda

Occidental of Abu Dhabi, LLC Delaware

Occidental of Abu Dhabi (Shah) Ltd. Bermuda

Occidental of Bahrain (Block 1) Ltd. Bermuda

Occidental of Bahrain (Block 3) Ltd. Bermuda

Occidental of Bahrain (Block 4) Ltd. Bermuda

Occidental of Bahrain (JOC Holding) LLC Delaware

Occidental of Bahrain (Offshore), LLC Delaware

Occidental of Bahrain Deep Gas, LLC Delaware

Occidental of Bahrain Ltd. Bermuda

Occidental of Bahrain Onshore Deep Gas, Ltd. Bermuda

Occidental of Dubai, Inc. Nevis

Occidental of Elk Hills, Inc. Delaware

Occidental of Iraq Holdings Ltd. Bermuda

Occidental of Iraq, LLC Delaware

Occidental of Oman, Inc. Nevis

Occidental of Yemen (Block 75), LLC Delaware

Occidental of Yemen (Block S-1), Inc. Cayman Islands

Occidental of Yemen Holdings (Block 75) Ltd. Bermuda

Occidental Oil and Gas Corporation Texas

Occidental Oil and Gas Holding Corporation California

Occidental Oil and Gas International, LLC Delaware
EXHIBIT 21 (cont'd)

Name Jurisdiction of Formation

Occidental Oil and Gas (Oman) Ltd. Nevis

Occidental Oil Asia Pte. Ltd. Singapore

Occidental Oman Gas Company LLC Delaware

Occidental Oman Gas Holdings Ltd. Bermuda

Occidental OOOI Holder, Inc. Delaware

Occidental Overseas Holdings BV The Netherlands

Occidental Overseas Operations, Inc. Delaware

Occidental Peninsula II, Inc. Nevis

Occidental Peninsula, LLC Delaware

Occidental Permian Ltd. Texas

Occidental Permian Manager LLC Delaware

Occidental Permian Services, Inc. Delaware

Occidental Petroleum Investment Co. California

Occidental Petroleum of Oman Ltd. Nevis

Occidental Petroleum of Qatar Ltd. Bermuda

Occidental Power Marketing, L.P. Delaware

Occidental Power Services, Inc. Delaware

Occidental PVC, LLC Delaware

Occidental Qatar Energy Company LLC Delaware

Occidental Quimica do Brasil Ltda. Brazil

Occidental Resources Company Cayman Islands

Occidental Shah Gas Holdings Ltd. Bermuda

Occidental Tower Corporation Delaware

Occidental Transportation Holding Corporation Delaware

Occidental Yemen Ltd. Bermuda

Occidental Yemen Sabatain, Inc. Nevis

OEVC Energy, LLC Texas

OEVC Midstream Projects, LLC Delaware

OOG Partner LLC Delaware

OOOI Chem Holdings, LLC Delaware

OOOI Chem Sub, LLC Delaware

OOOI Chemical International, LLC Delaware

OOOI Chemical Management, Inc. Delaware

OOOI Chile Holder, Inc. Nevis

OOOI Oil and Gas Management, Inc. Delaware

OOOI Oil and Gas Sub, LLC Delaware

Opcal Insurance, Inc. Hawaii

OPM GP, Inc. Delaware

Oxy BridgeTex Limited Partnership Texas

Oxy BT Holdings GP, Inc. Texas

Oxy BT Holdings LP, Inc. Texas

Oxy Cogeneration Holding Company, Inc. Delaware

Oxy Colombia Holdings, Inc. Delaware

OXY CV Pipeline LLC Delaware

Oxy Dolphin E&P, LLC Nevis

Oxy Dolphin Pipeline, LLC Nevis

Oxy Energy Canada, Inc. Delaware

Oxy Energy Services, Inc. Delaware
EXHIBIT 21 (cont'd)

Name Jurisdiction of Formation

Oxy Expatriate Services, Inc. Delaware

Oxy Holding Company (Pipeline), Inc. Delaware

OXY Inc. California

Oxy Ingleside Energy Center, LLC Delaware

OXY Libya E&P Concession 103 Ltd. Bermuda

OXY Libya E&P EPSA 102 B.V. The Netherlands

OXY Libya E&P EPSA 1981 Ltd. Bermuda

OXY Libya E&P EPSA 1985 Ltd. Bermuda

OXY Libya E&P NC 143, 144, 145, 150 B.V. The Netherlands

OXY Libya, LLC Delaware

OXY LNG, Inc. Delaware

OXY Little Knife, LLC Delaware

OXY Long Beach, Inc. Delaware

OXY Lost Hills, Inc. Delaware

OXY LPG LLC Delaware

Oxy LPG Terminal, LLC Delaware

Oxy Midstream Strategic Development LLC Delaware

OXY NM LP Texas

OXY Oil Partners, Inc. Delaware

Oxy Oleoducto SOP, LLC Delaware

Oxy Overseas Services Ltd. Bermuda

OXY PBLP Holder, Inc. Delaware

OXY PBLP Manager, LLC Delaware

Oxy Pipeline I Company Delaware

OXY Support Services, LLC Delaware

OXY Tidelands, Inc. Delaware

Oxy Transport I Company Delaware

OXY USA Inc. Delaware

OXY USA WTP LP Delaware

Oxy Vinyls Canada Co. Nova Scotia

Oxy Vinyls, LP Delaware

OXY VPP Investments, Inc. Delaware

OXY West, LLC Texas

Oxy Westwood Corporation California

OXY Wilmington, LLC Delaware

Oxy Y-1 Company New Mexico

OxyChile Investments, LLC Delaware

Oxycol Holder Ltd. Bermuda

OXYMAR Texas

Permian Basin Limited Partnership Delaware

Permian VPP Holder, LP Delaware

Permian VPP Manager, LLC Delaware

Phibro (Asia) Pte. Ltd. Singapore

Phibro Commodities Limited United Kingdom

Phibro GmbH Switzerland

Phibro LLC Delaware

Phibro Limited United Kingdom

Phibro Service LLC Delaware
EXHIBIT 21 (cont'd)

Name Jurisdiction of Formation

Phibro Trading LLC Delaware

Placid Oil Company Delaware

Rio de Viento, Inc. Wyoming

San Patricio Pipeline LLC Delaware

Scanports Ltd. United Kingdom

Scanports Shipping, Inc. Delaware

Shipalks Shipping Ltd. United Kingdom

Southern San Joaquin Production, LLC Delaware

Swiflite Aircraft Corporation New Jersey

Tenby, Inc. California

Thums Long Beach Company Delaware

Tidelands Oil Production Company Texas

Turavent Oil AG Switzerland

Vintage Gas, Inc. Oklahoma

Vintage Petroleum Boliviana, Ltd. Bermuda

Vintage Petroleum International Finance B.V. Netherlands

Vintage Petroleum International Holdings, Inc. Delaware

Vintage Petroleum International Ventures, Inc. Cayman Islands

Vintage Petroleum International, Inc. Oklahoma

Vintage Petroleum South America Holdings, Inc. Cayman Islands

Vintage Petroleum South America, LLC Oklahoma

Vintage Petroleum, LLC Delaware

Vintage Production California LLC Delaware
EXHIBIT 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors

Occidental Petroleum Corporation:

We consent to the incorporation by reference in the registration statements (Nos. 33-64719, 333-55404, 333-63444, 333-78031, 333-

83124, 333-96951, 333-104827, 333-124732, 333-142705 and 333-176308) on Forms S-3 and S-8 of Occidental Petroleum Corporation of

our reports dated February 26, 2013, with respect to the consolidated balance sheets of Occidental Petroleum Corporation as of December 31, 2012

and 2011, and the related consolidated statements of income, comprehensive income, stockholders’ equity, and cash flows for each of the years in

the three-year period ended December 31, 2012 and the related financial statement schedule, and the effectiveness of internal control over financial

reporting as of December 31, 2012, which reports appear in the December 31, 2012 annual report on Form 10-K of Occidental Petroleum

Corporation.

/s/ KPMG LLP

Los Angeles, California

February 26, 2013
EXHIBIT 23.2

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

To the Board of Directors

Occidental Petroleum Corporation:

We consent to the (i) inclusion in the Occidental Petroleum Corporation (Occidental) Form 10-K for the year ended December 31, 2012,

and the incorporation by reference in Occidental's registration statements (Nos. 33-64719, 333-55404, 333-63444, 333-78031, 333-83124,

333-96951, 333-104827, 333-124732, 333-142705 and 333-176308) (the “Registration Statements”), of references to our name and to our

letter dated February 5, 2013, relating to our review of the methods and procedures used by Occidental for estimating its oil and gas proved reserves

(our “Letter”), (ii) filing of our Letter with the Securities and Exchange Commission as Exhibit 99.1 to the Form 10-K and (iii) incorporation by

reference of our Letter in the Registration Statements.

/s/ RYDER SCOTT COMPANY, L.P.

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

Houston, Texas

February 26, 2013
EXHIBIT 31.1

RULE 13a – 14(a) / 15d – 14(a)

CERTIFICATION

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

I, Stephen I. Chazen, certify that:

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

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact

necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading

with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all

material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in

this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures

(as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act

Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under

our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is

made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be

designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the

preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our

conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this

report based on such evaluation; and

(d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the

registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially

affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial

reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the

equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting

which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial

information; and 

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the

registrant's internal control over financial reporting.

Date: February 26, 2013

/s/ STEPHEN I. CHAZEN

Stephen I. Chazen

President and Chief Executive Officer
EXHIBIT 31.2

RULE 13a – 14(a) / 15d – 14(a)

CERTIFICATION

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

I, Cynthia L. Walker, certify that:

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

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact

necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading

with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all

material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in

this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures

(as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act

Rules 13a-15(f) and 15d-15(f)) for the registrant and have: 

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under

our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is

made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be

designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the

preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our

conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this

report based on such evaluation; and

(d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the

registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially

affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial

reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the

equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting

which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial

information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the

registrant's internal control over financial reporting.

Date: February 26, 2013

/s/ CYNTHIA L. WALKER

Cynthia L. Walker

Executive Vice President and

Chief Financial Officer
EXHIBIT 32.1

CERTIFICATION OF CEO AND CFO PURSUANT TO

18 U.S.C. § 1350,

AS ADOPTED PURSUANT TO

§ 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report on Form 10-K of Occidental Petroleum Corporation (the “Company”) for the fiscal period ended

December 31, 2012, as filed with the Securities and Exchange Commission on February 26, 2013 (the “Report”), Stephen I. Chazen, as

Chief Executive Officer of the Company, and Cynthia L. Walker, as Chief Financial Officer of the Company, each hereby certifies, pursuant

to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that, to the best of his or her knowledge, respectively:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the

Company.

/s/ STEPHEN I. CHAZEN

Name: Stephen I. Chazen

Title: President and Chief Executive Officer

Date: February 26, 2013

/s/ CYNTHIA L. WALKER

Name: Cynthia L. Walker

Title: Executive Vice President and Chief Financial Officer

Date: February 26, 2013

A signed original of this written statement required by Section 906 has been provided to Occidental Petroleum Corporation and will be

retained by Occidental Petroleum Corporation and furnished to the Securities and Exchange Commission or its staff upon request.

This certification accompanies the Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and shall not, except to the extent

required by the Sarbanes-Oxley Act of 2002, be deemed filed by the Company for purposes of Section 18 of the Securities Exchange Act of

1934, as amended.
EXHIBIT 99.1

OCCIDENTAL PETROLEUM CORPORATION

Process Review

of the

Estimated

Future Reserves and Income

Attributable to Certain

Fee, Leasehold and Royalty Interests

and

Certain Economic Interests

Derived Through Certain Production Sharing Contracts

SEC Parameters

As of

December 31, 2012

\s\ Jennifer Fitzgerald

Jennifer A. Fitzgerald, P.E.

TBPE License No. 100572

Vice President

[SEAL]

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
TBPE REGISTERED ENGINEERING FIRM F-1580 FAX (713) 651-0849

1100 LOUISIANA SUITE 4600 HOUSTON, TEXAS 77002-5294 TELEPHONE (713) 651-9191

February 5, 2013

Occidental Petroleum Corporation

10889 Wilshire Boulevard, 16th Floor

Los Angles, California 90024

Ladies and Gentlemen:

At your request, Ryder Scott Company, L.P. (Ryder Scott) has conducted a process review of the methods and

analytical procedures utilized by the engineering and geological staff of Occidental Petroleum Corporation (Occidental) for

estimating the proved reserves volumes, preparing the economic evaluations and determining the reserves classifications as

of December 31, 2012, based on the definitions and disclosure guidelines of the United States Securities and Exchange

Commission (SEC) Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released

January 14, 2009 in the Federal Register (SEC regulations). The results of our third party reserves process review, completed

on January 10, 2013 and presented herein, were prepared for public disclosure by Occidental in filings made with the SEC in

accordance with the disclosure requirements set forth under Section 229.1202(a)(8) of the SEC regulations.

Based on our review, including the data, technical processes and interpretations presented by Occidental, it is our

opinion that the overall procedures and methodologies utilized by Occidental in estimating the proved reserves volumes,

documenting the changes in reserves from prior estimates, preparing the economic evaluations and determining the reserves

classifications for the reviewed properties are appropriate for the purpose thereof, and comply with the SEC regulations as of

December 31, 2012. Ryder Scott has not been engaged to render an opinion as to the reasonableness of reserves quantities

reported by Occidental.

Properties Reviewed

The proved reserves reviewed herein are attributable to the fee, leasehold and royalty interests of Occidental in certain

properties located in the United States in the states of California, Colorado, Kansas, and Texas and derived through

Occidental’s economic interest as defined in certain production sharing contracts for certain properties located in the Middle

East.

The properties reviewed herein were selected by Occidental. Ryder Scott and Occidental concur that these properties

are a valid representation of Occidental’s total net proved reserves portfolio as of December 31, 2012. Based on the estimates

prepared by Occidental, the portion of total company net liquid and net gas reserves reviewed by us are expressed as a

percentage and presented in summary form on the following page. At Occidental’s request, we have also presented the

portion of the total company net reserves reviewed by us on a barrel of oil equivalent (BOE) basis.

SUITE 600, 1015 4TH STREET, S.W. CALGARY, ALBERTA T2R 1J4 TEL (403) 262-2799 FAX (403) 262-2790

621 17TH STREET, SUITE 1550 DENVER, COLORADO 80293-1501 TEL (303) 623-9147 FAX (303) 623-4258
Occidental Petroleum Corporation

February 5, 2013

Page 2

Percentage of Total Company Estimated Net Reserves

Reviewed by Ryder Scott

SEC Parameters

Occidental Petroleum Corporation

As of December 31, 2012

 Oil/Condensate NGL Total Liquid Hydrocarbons Gas Equivalent MMBOE

Total Proved Developed 12% 50% 17% 41% 24%

Total Proved Undeveloped 7% 15% 8% 12% 9%

Total Company Proved 11% 38% 15% 33% 20%

The net liquid hydrocarbons reviewed are comprised of oil, condensate and natural gas liquids (NGL) and are based

on standard 42 gallon barrels. All net gas volumes reviewed are based on an “as sold” basis expressed in millions of cubic

feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located. Reserves

reviewed and noted herein on an equivalent barrel (BOE) basis are based on converting natural gas on the basis of relative

energy content using a factor of 6,000 cubic feet of natural gas per one barrel of oil equivalent. It should be noted that barrel of

oil equivalence does not necessarily result in price equivalence as the equivalent price of natural gas on a barrel of oil

equivalent basis is, and has been substantially lower than the corresponding price for crude oil currently and over the recent

past.

Reserves Process Review Discussion

A process review, according to Paragraph 2.2(h) contained in the Society of Petroleum Engineers (SPE) Standards

Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (SPE auditing standards), is “the result of an

investigation to address the adequacy and effectiveness of an entity’s internal processes and controls relative to reserves

estimation.”

In order to arrive at our conclusions and to substantiate our opinion relative to Occidental’s internal reserves estimation

process and controls, we conducted our investigation in a manner that closely conforms to the SPE auditing standards for a

reserves audit. Under Paragraph 2.2(f) of the SPE auditing standards, a reserves audit includes “the process of reviewing

certain of the pertinent facts interpreted and assumptions made that have resulted in an estimate of reserves and/or Reserves

Information prepared by others and the rendering of an opinion about (1) the appropriateness of the methodologies employed,

(2) the adequacy and quality of the data relied upon, (3) the depth and thoroughness of the reserves estimation process, and

(4) the classification of reserves appropriate to the relevant definitions used.”

Our process review, however, differs from an SPE reserves audit in that we have not conducted our investigation with

sufficient rigor to express an opinion as to “the reasonableness of the estimated reserve quantities and/or the Reserves

Information” as required under item (5) Paragraph 2.2(f) of the SPE auditing standards for a reserves audit. Our review should

not be construed to be a complete and comprehensive appraisal of the subject properties or deemed to convey the same

level of information contained in a third party reserves audit or reserves evaluation report.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
Occidental Petroleum Corporation

February 5, 2013

Page 3

Applicable Petroleum Reserves Definitions

The determination of the proved reserves classifications as discussed herein are based on the definitions as set forth

in the Securities and Exchange Commission’s Regulations Part 210.4-10(a) released January 14, 2009 in the Federal

Register, Volume 74, pages 2158 through 2197.

Reserves and Uncertainty

The SEC defines reserves as the “estimated remaining quantities of oil and gas and related substances anticipated to

be economically producible, as of a given date, by application of development projects to known accumulations.” All reserve

estimates involve an assessment of the uncertainty relating to the likelihood that the actual remaining quantities recovered will

be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends

chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of

these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications,

either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further subclassified as probable and possible reserves to denote progressively increasing uncertainty as to their recoverability.

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this

data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a

range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental

quantities of the reserves. If the reserves quantities are estimated using the deterministic incremental approach, the

uncertainty for each discrete incremental quantity of the reserves is addressed by the reserves category assigned by the

evaluator. Therefore, it is the categorization of reserve quantities as proved, probable or possible that addresses the inherent

uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable

certainty that the estimates of the quantities actually recovered are “much more likely to be achieved than not.” The SEC

defines probable reserves as “those additional reserves that are less certain to be recovered than proved reserves but which,

together with proved reserves, are as likely as not to be recovered.” The SEC defines possible reserves as “those additional

reserves that are less certain to be recovered than probable reserves.” All quantities of reserves within the same reserves

category must meet the SEC definitions as noted above.

The reserves for the properties reviewed by us were estimated by Occidental using deterministic methods and

presented as incremental quantities. Under the deterministic incremental approach, discrete quantities of reserves are

estimated and assigned separately as proved, probable or possible based on their individual level of uncertainty. At

Occidental’s request, this reserves process review addresses only the proved reserves attributable to the properties reviewed

herein.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as

economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of

geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate

recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.”

Moreover, estimates of proved, probable and possible reserves quantities and their associated reserves categories may be

revised due to other factors such as the results of future operations, effects of regulation by governmental agencies or

geopolitical or economic risks.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
Occidental Petroleum Corporation

February 5, 2013

Page 4

Reserves Process Review Procedure

Certain technical personnel responsible for the preparation of Occidental’s proved reserves estimates presented the

data, methods and procedures used in 1) estimating the reserves volumes as of December 31, 2012; 2) documenting the

changes in reserves from prior estimates; 3) preparing the economic evaluations associated with the estimated December 31,

2012 reserves; and 4) determining the reserves classifications for each of the subject properties reviewed. We consulted with

these technical personnel and had access to their workpapers and supporting data in the course of our review. Furthermore, if

in the course of our examination something came to our attention which brought into question the appropriateness of the

methodologies employed, the adequacy of the data relied upon or the documentation of the reserves estimation process,

additional clarification was requested from Occidental until we had satisfactorily resolved our questions relating thereto.

Methodology and Procedure Employed by Occidental for Estimating Reserves

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the

quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with

those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s

Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of

certain analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based

methods; (2) volumetric-based methods; and (3) analogy. These methods may be used singularly or in combination by the

reserves evaluator in the process of estimating the quantities of reserves. Reserves evaluators must select the method or

combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable

geoscience and engineering data available at the time of the estimate, the established or anticipated performance

characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property.

The proved reserves for the properties that we reviewed were estimated by performance methods, analogy, reservoir

modeling or a combination of methods. Approximately 43 percent of the proved reserves attributable to producing wells or

reservoirs for the properties reviewed were estimated by performance methods using decline curve analysis and/or material

balance which utilized extrapolations of historical production and pressure data in those cases where such data were

considered to be definitive. The remaining 57 percent of the proved reserves attributable to the producing wells for the

properties reviewed were estimated by a combination of methods including type curves supported by analogs and reservoir

modeling to 1) estimate those reserves where there were inadequate historical performance data to establish a definitive

producing trend and 2) estimate the incremental reserves attributable to enhanced/improved oil recovery. The data used by

Occidental in their analysis of the proved reserves for the producing properties reviewed by us was considered sufficient for

the purpose thereof.

Approximately 15 percent of the proved developed non-producing reserves were estimated by performance methods

using analogy to prior established decline trends. The remaining 85 percent of the proved developed non-producing reserves

and all of the proved undeveloped reserves were estimated by a combination of methods including type curves supported by

analogs and reservoir modeling as noted above. The data used by Occidental in their analysis of the non-producing and

undeveloped reserves for the properties reviewed by us was considered sufficient for the purpose thereof.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
Occidental Petroleum Corporation

February 5, 2013

Page 5

Of the properties reviewed, approximately 26 percent of the proved producing reserves and 38 percent of the proved

non-producing and undeveloped reserve volumes are related to the application of enhanced/improved recovery techniques.

These enhanced/improved recovery techniques include water and CO 2 injection and infill drilling.

Occidental uses the latest available production, new well and seismic data in its reserves estimation process.

Typically, this data is from the third quarter of the year for which reserves are estimated, though material data is considered

whenever it becomes available prior to finalization of reserves estimates. The data used by Occidental in their analysis of the

proved reserves for the properties reviewed by us was considered sufficient for the purpose thereof.

Primary Economic Assumptions Employed by Occidental for Estimating Reserves

To estimate economically recoverable proved reserves and related future net cash flows, Occidental considered many

factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and

engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements,

and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be

anticipated to be economically producible from a given date forward based on existing economic conditions including the

prices and costs at which economic producibility from a reservoir is to be determined. To confirm that the proved reserves

reviewed by us meet the SEC requirements to be economically producible, we have reviewed certain primary economic data

utilized by Occidental relating to hydrocarbon prices and costs as noted herein.

The hydrocarbon prices in effect on December 31, 2012 for the properties reviewed were determined by Occidental

using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the

hydrocarbons are sold and adjustments for differentials as described herein. In certain geographic areas, the price reference

and benchmark prices may be defined by contractual arrangements. For hydrocarbon products sold under contract, the

contract prices including fixed and determinable escalations, exclusive of inflation adjustments, were used until expiration of

the contract.

The table below summarizes Occidental’s net volume weighted benchmark prices adjusted for differentials for the

properties reviewed by us and referred to herein as Occidental’s “average realized prices.” The average realized prices

shown in the table below were determined from Occidental’s estimate of the total future gross revenue before production taxes

for the properties reviewed by us and Occidental’s estimate of the total net reserves for the properties reviewed by us for the

geographic area. A summary of average realized prices are not included for certain properties located in the Middle East

because of the host government’s limitations on the disclosure of commercially sensitive information. The data shown in the

table below is presented in accordance with SEC disclosure requirements for each of the geographic areas reviewed by us.

Geographic Area Product

Price

Reference

Average

Benchmark

Prices

Average Realized

Prices

North America

United States Oil/Condensate WTI Cushing $94.71/Bbl $93.76/Bbl

NGLs WTI Cushing $94.71/Bbl $35.33/Bbl

Gas Henry Hub $2.79/MMBTU $2.95/MCF

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
Occidental Petroleum Corporation

February 5, 2013

Page 6

As indicated above, the product prices that were used by Occidental to determine the future gross revenue for each

property reviewed by us reflect adjustments to the benchmark prices for gravity, quality, local conditions, gathering and

transportation fees and distance from market, referred to herein as “differentials.” The differentials used by Occidental were

accepted as factual data. We have not conducted an independent verification of the data used by Occidental.

While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs

and other costs relating to such production may also increase or decrease from existing levels, such changes were, in

accordance with rules adopted by the SEC, omitted from consideration by Occidental in this process and omitted by us in

conducting this review.

Accumulated gas production imbalances, if any, were not taken into account in the proved reserve estimates of gas

reviewed. The proved gas volumes included herein attribute gas consumed in operations as reserves for those fields where

the inclusion of such volumes was appropriate.

Operating costs used by Occidental are based on the operating expense reports of Occidental and include only those

costs directly applicable to the leases or wells for the properties reviewed by us. The operating costs include a portion of

general and administrative costs allocated directly to the leases and wells. For operated properties, the operating costs include

an appropriate level of corporate general administrative and overhead costs. The operating costs for non-operated properties

include the Council of Petroleum Accounting Societies overhead costs that are allocated directly to the leases and wells under

terms of operating agreements. The operating costs used by Occidental were accepted as factual data and reviewed by us for

their reasonableness; however, we have not conducted an independent verification of the data used by Occidental.

Development costs used by Occidental are based on authorizations for expenditure (AFE) for the proposed work or

actual costs for similar projects. The development costs used by Occidental were accepted as factual data and reviewed by

us for their reasonableness; however, we have not conducted an independent verification of the data used by Occidental.

The proved developed non-producing and undeveloped reserves for the properties reviewed by us were incorporated

by Occidental in accordance with Occidental’s plans to develop these reserves as of December 31, 2012. The

implementation of Occidental’s development plans as presented to us is subject to the approval process adopted by

Occidental’s management. As a result of our inquiries during the course of our review, Occidental has informed us that the

development activities for the properties reviewed by us have been subjected to and received the internal approvals required

by Occidental’s management at the appropriate local, regional and corporate level. In addition to the internal approvals as

noted, certain development activities may still be subject to partner AFE processes, Joint Operating Agreement requirements

or other administrative approvals external to Occidental. Additionally, Occidental has informed us that they are not aware of

any legal, regulatory, political or economic obstacles that would significantly alter their plans.

Future Production Rate Assumptions Employed by Occidental for Estimating Reserves

Occidental’s forecasts of future production rates are based on historical performance from wells currently on production.

If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of

curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then

applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating

future production rates.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
Occidental Petroleum Corporation

February 5, 2013

Page 7

Test data and other related information were used by Occidental to estimate the anticipated initial production rates for

those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence

at an anticipated date determined by Occidental. Wells or locations that are not currently producing may start producing earlier

or later than anticipated in Occidental’s estimates due to unforeseen factors causing a change in the timing to initiate

production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing or

recompleting wells and constraints set by regulatory bodies.

The future production rates from wells currently on production or wells or locations that are not currently producing may

be more or less than estimated by Occidental because of changes including, but not limited to, reservoir performance,

operating conditions related to surface facilities, compression and artificial lift, pipeline capacity or other operating conditions,

market demand and allowables or other constraints set by regulatory bodies.

Reserves Derived by Occidental Through Certain Production Sharing Contracts

The reserves for certain properties located in the Middle East reviewed herein are limited to the period prior to

expiration of current contracts providing the legal right to produce or an economic interest in such production. Furthermore,

properties in different countries may be subjected to significantly varying contractual fiscal terms that affect the net revenue to

Occidental for the production of these volumes. The prices and economic return received for these net volumes can vary

significantly based on the terms of these contracts. Therefore, when applicable, Ryder Scott reviewed the fiscal terms of such

contracts and discussed with Occidental the net economic benefit attributed to such operations for the determination of the net

hydrocarbon volumes and income thereof. Occidental’s net hydrocarbon volumes for the fields reviewed in the Middle East

include certain amounts corresponding to in-country income taxes where the terms of the production sharing contract include

provisions for an in-kind settlement process, where production is immediately taken and sold to pay the local income tax for

and on behalf of the contractor (in this case Occidental). Ryder Scott has not conducted an exhaustive audit or verification of

such contractual information. Neither our review of such contractual information nor our acceptance of Occidental’s

representations regarding such contractual information should be construed as a legal opinion on this matter.

Possible Effects of Regulation on Occidental’s Estimate of Reserves

Ryder Scott did not evaluate the country and geopolitical risks in the countries where Occidental operates or has

interests. Occidental’s operations may be subject to various levels of governmental controls and regulations. These controls

and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce

hydrocarbons including the granting, extension or termination of production sharing contracts, the fiscal terms of various

production sharing contracts, drilling and production practices, environmental protection, marketing and pricing policies,

royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in

governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved

income actually received to differ significantly from the quantities estimated by Occidental as reviewed herein.

We have not made any field examination of the properties. No consideration was given in this review to potential

environmental liabilities that may exist nor to any costs for the potential liabilities to restore and clean up damages, if any,

caused by past operating practices.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
Occidental Petroleum Corporation

February 5, 2013

Page 8

Occidental has informed us that they are not aware of any legal, regulatory, political, environmental or economic

obstacles that currently are expected to materially impact their ability to recover the estimated proved reserves for the

properties reviewed by us.

Data Reviewed in Conducting the Third Party Reserves Process Review

Occidental has informed us that they have furnished or otherwise made available to us all of the material accounts,

records, geological and engineering data, and reports and other data required for this review. In conducting our process review

of Occidental’s estimates of proved reserves, forecasts of future production and income, we have reviewed data used by

Occidental with respect to property interests owned or otherwise held, production and well tests from examined wells, normal

direct costs of operating the wells or leases, other costs such as transportation and processing fees, ad valorem and

production taxes, recompletion and development costs, product prices based on the SEC regulations, adjustments or

differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements.

Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of

the data utilized by Occidental. We consider the factual data utilized by Occidental to be appropriate and sufficient for the

purpose of our review of the methods and analytical procedures utilized by the engineering and geological staff of Occidental

for estimating the proved reserves volumes and preparing the economic evaluations.

Reserves Process Review Opinion

We found no bias in the utilization and analysis of data in proved reserves estimates for these properties. Furthermore,

we found the estimation process incorporated all pertinent data, utilized a thorough and detailed analytical approach and was

supported by a well documented audit trail.

We consider the assumptions, data, methods and analytical procedures used by Occidental and as reviewed by us

appropriate for the purpose thereof, and we have used all such methods and procedures that we consider necessary and

appropriate under the circumstances to render the conclusions set forth herein.

Based on our review, including the data, technical processes and interpretations presented by Occidental, it is our

opinion that the overall procedures and methodologies utilized by Occidental in estimating the proved reserves volumes,

documenting the changes in reserves from prior estimates, preparing the economic evaluations and determining the reserves

classifications for the reviewed properties comply with the SEC regulations as of December 31, 2012. Ryder Scott has not

been engaged to render an opinion as to the reasonableness of reserves quantities reported by Occidental.

Standards of Independence and Professional Qualification

Ryder Scott is an employee-owned independent petroleum engineering consulting firm. We do not serve as officers or

directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating

and investment decision-making process of our clients. No single client or job represents a material portion of our annual

revenue. These factors allow us to maintain our independence and objectivity in the performance of our services.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
Occidental Petroleum Corporation

February 5, 2013

Page 9

Ryder Scott requires that staff engineers and geoscientists receive professional accreditation in the form of a registered

or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent

thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.

We are independent petroleum engineers with respect to Occidental. Neither we nor any of our employees have any

interest in the subject properties and neither the employment to do this work nor the compensation is contingent on the results

of our review.

The results of the reserves process review, presented herein, are based on technical analysis conducted by teams of

geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person

primarily responsible for overseeing the review of the reserves information discussed in this report, are included as an

attachment to this letter.

Terms of Usage

The results of our third party reserves process review, presented in report form herein, were prepared in accordance

with the disclosure requirements set forth in the SEC regulations and are intended for public disclosure as an exhibit in filings

made with the SEC by Occidental.

Occidental makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, Occidental

has certain registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form

10-K is incorporated by reference. We have consented to the incorporation by reference in the registration statements on Form

S-3 and Form S-8 of Occidental of the references to our name as well as to the references to our third party report for

Occidental, which appear in the December 31, 2012 annual report on Form 10-K of Occidental, the inclusion in that Form 10-

K of such references and the filing of such report as an exhibit to such 10-K. Our written consent for such use is included as a

separate exhibit to the filings made with the SEC by Occidental.

We have provided Occidental with a digital version of the original signed copy of this report letter. In the event there are

any differences between the digital version included in filings made by Occidental and the original signed report letter, the

original signed report letter shall control and supersede the digital version.

The data and work papers used in the preparation of this report are available for examination by authorized parties in

our offices. Please contact us if we can be of further service.

Very truly yours,

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

\s\ Jennifer Fitzgerald

Jennifer A. Fitzgerald, P.E.

TBPE License No. 100572

Vice President

[SEAL]

JAF (FPR)/pl

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and

engineers from Ryder Scott Company, L.P. Jennifer A. Fitzgerald was the primary technical person responsible for overseeing

the reserves audit conducted by Ryder Scott of the estimates of reserves presented herein.

Mrs. Fitzgerald, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 2006, is a Vice President responsible for

coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide.

Before joining Ryder Scott, Mrs. Fitzgerald served in a number of engineering positions with ExxonMobil. For more information

regarding Mrs. Fitzgerald’s geographic and job specific experience, please refer to the Ryder Scott Company website at

www.ryderscott.com/Experience/Employees.

Mrs. Fitzgerald earned a Bachelor of Science degree in Chemical Engineering from University of Illinois Urbana-Champaign in

2001 and is a registered Professional Engineer in the State of Texas. She is also a member of the Society of Petroleum

Evaluation Engineers and Society of Petroleum Engineers. She currently serves as the Chairman of the Houston Chapter of the

Society of Petroleum Evaluation Engineers.

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers

requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional

ethics, which Mrs. Fitzgerald fulfills. As part of her 2012 continuing education hours, Mrs. Fitzgerald attended 9 hours of

formalized training including the 2012 RSC Reserves Conference and various professional society presentations specifically

relating to the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title

17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the

Federal Register. Mrs. Fitzgerald attended an additional 12.5 hours of formalized external training during 2012 covering such

topics as reservoir engineering, geoscience and petroleum economics evaluation methods, procedures and software and

ethics for consultants. She also presented presentations at the 2012 RSC Reserves Conference, the 2012 North American

Petroleum Accounting Conference (NAPAC), and the 2012 National Oil and Gas Reserves Conference held by AICPA/PDI

relating to the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title

17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the

Federal Register. Mrs. Fitzgerald also previously attended the one and two day short courses presented by Dr. John Lee

specific to the new SEC regulations.

Based on her educational background, professional training and more than 11 years of practical experience in the estimation

and evaluation of petroleum reserves, Mrs. Fitzgerald has attained the professional qualifications as a Reserves Estimator and

Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves

Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
PETROLEUM RESERVES DEFINITIONS

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

PREAMBLE

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of

Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The

“Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of

Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies

Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to

Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take

effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after

January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part

210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC

document are denoted in italics herein).

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically

producible, as of a given date, by application of development projects to known accumulations. All reserve estimates

involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or

less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the

amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The

relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or

unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as

probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC

regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of

probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit

disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any

document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state

law as noted in §229.1202 Instruction to Item 1202.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as

economic conditions change.

Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods

include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery.

Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding,

and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the

future as petroleum technology continues to evolve.

Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum

accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics,

extraction method applied, or degree of processing prior to sale. Examples of unconventional petroleum accumulations include

coalbed or coalseam methane (CBM/CSM), basinRYDER SCOTT COMPANY PETROLEUM CONSULTANTS
PETROLEUM RESERVES DEFINITIONS

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centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may

require specialized extraction technology and/or significant processing prior to sale.

Reserves do not include quantities of petroleum being held in inventory.

Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from

different reserves categories.

RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be

economically producible, as of a given date, by application of development projects to known accumulations. In addition,

there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue

interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and

financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing,

faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to

areas that are clearly separated from a known accumulation by a non-productive reservoir ( i.e., absence of reservoir,

structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially

recoverable resources from undiscovered accumulations).

PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as

follows:

Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of

geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given

date forward, from known reservoirs, and under existing economic conditions, operating methods, and government

regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal

is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project

to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the

project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous

with it and to contain economically producible oil or gas on the basis of available geoscience and engineering

data.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
PETROLEUM RESERVES DEFINITIONS

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PROVED RESERVES (SEC DEFINITIONS) CONTINUED

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known

hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable

technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the

potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of

the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher

contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including,

but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in

the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or

other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on

which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including

governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be

determined. The price shall be the average price during the 12-month period prior to the ending date of the period

covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each

month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon

future conditions.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)

Sponsored and Approved by:

SOCIETY OF PETROLEUM ENGINEERS (SPE)

WORLD PETROLEUM COUNCIL (WPC)

AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)

SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)

Reserves status categories define the development and producing status of wells and reservoirs. Reference should be

made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following

reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the

aforementioned SEC and SPE-PRMS documents are denoted in italics herein).

DEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as

follows:

Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required

equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate

if the extraction is by means not involving a well.

Developed Producing (SPE-PRMS Definitions)

While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further subclassified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

Developed Producing Reserves

Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing

at the time of the estimate.

Improved recovery reserves are considered producing only after the improved recovery project is in operation.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

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Developed Non-Producing

Developed Non-Producing Reserves include shut-in and behind-pipe reserves.

Shut-In

Shut-in Reserves are expected to be recovered from:

(1) completion intervals which are open at the time of the estimate, but which have not started producing;

(2) wells which were shut-in for market conditions or pipeline connections; or

(3) wells not capable of production for mechanical reasons.

Behind-Pipe

Behind-pipe Reserves are expected to be recovered from zones in existing wells, which will require additional

completion work or future re-completion prior to start of production.

In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a

new well.

UNDEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as

follows:

Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on

undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas

that are reasonably certain of production when drilled, unless evidence using reliable technology exists

that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been

adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances,

justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for

which an application of fluid injection or other improved recovery technique is contemplated, unless such

techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as

defined in [Regulation S-X §210.4-10(a)(2)], or by other evidence using reliable technology establishing

reasonable certainty.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS