10-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

þAnnual 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, 2014	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	5 Greenway Plaza, Suite 110, Houston, Texas
Zip Code	77046
Registrant's telephone number, including area code	(713) 215-7000

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, $.20 par value	New York Stock Exchange

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

Indicatebycheckmarkiftheregistrantisawell-knownseasonedissuer,asdefinedinRule405oftheSecuritiesAct. Yes þ 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  þ

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 þ   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 þ   No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.   þ

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, 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	þ	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  þ

The aggregate market value of the voting common stock held by nonaffiliates of the registrant was approximately $79.8 billion,computed by reference to the closing price on the New York Stock Exchange composite tape of $102.63 per share of Common Stock on June 30, 2014.  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, 2015, there were 770,550,364 shares of Common Stock outstanding, par value $0.20 per share.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s definitive Proxy Statement, relating to its May 1, 2015 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 and Marketing Operations...............................................................................................................................	5
	Capital Expenditures.........................................................................................................................................................	6
	Employees.........................................................................................................................................................................	6
	Environmental Regulation.................................................................................................................................................	6
	Available Information.........................................................................................................................................................	6
Item 1A	Risk Factors.............................................................................................................................................................................	6
Item 1B	Unresolved Staff Comments....................................................................................................................................................	8
Item 3	Legal Proceedings...................................................................................................................................................................	8
Item 4	Mine Safety Disclosures..........................................................................................................................................................	8
	Executive Officers....................................................................................................................................................................	9
Part II
Item 5	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities...............	10
Item 6	Selected Financial Data..........................................................................................................................................................	12
Item 7	Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A).....................................	12
	Strategy.............................................................................................................................................................................	13
	Oil and Gas Segment........................................................................................................................................................	14
	Chemical Segment............................................................................................................................................................	20
	Midstream and Marketing Segment..................................................................................................................................	21
	Segment Results of Operations.........................................................................................................................................	22
	Significant Items Affecting Earnings..................................................................................................................................	25
	Taxes.................................................................................................................................................................................	25
	Consolidated Results of Operations..................................................................................................................................	26
	Consolidated Analysis of Financial Position......................................................................................................................	27
	Liquidity and Capital Resources........................................................................................................................................	27
	Off-Balance-Sheet Arrangements......................................................................................................................................	29
	Contractual Obligations.....................................................................................................................................................	29
	Lawsuits, Claims and Contingencies.................................................................................................................................	30
	Environmental Liabilities and Expenditures.......................................................................................................................	30
	Foreign Investments..........................................................................................................................................................	32
	Critical Accounting Policies and Estimates........................................................................................................................	32
	Significant Accounting and Disclosure Changes...............................................................................................................	35
	Safe Harbor Discussion Regarding Outlook and Other Forward-Looking Data................................................................	36
Item 7A	Quantitative and Qualitative Disclosures About Market Risk..................................................................................................	36
Item 8	Financial Statements and Supplementary Data......................................................................................................................	38
	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.............................................................................................................	44
	Consolidated Statements of Cash Flows...........................................................................................................................	45
	Notes to Consolidated Financial Statements.....................................................................................................................	46
	Quarterly Financial Data (Unaudited)................................................................................................................................	77
	Supplemental Oil and Gas Information (Unaudited)..........................................................................................................	79
	Financial Statement Schedule:
	Schedule II – Valuation and Qualifying Accounts..............................................................................................................	93
Item 9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure..................................................	94
Item 9A	Controls and Procedures.........................................................................................................................................................	94
	Management's Annual Assessment of and Report on Internal Control Over Financial Reporting.....................................	94
	Disclosure Controls and Procedures.................................................................................................................................	94
Item 9B	Other Information....................................................................................................................................................................	94
Part III
Item 10	Directors, Executive Officers and Corporate Governance......................................................................................................	95
Item 11	Executive Compensation........................................................................................................................................................	95
Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters................................	95
Item 13	Certain Relationships and Related Transactions and Director Independence........................................................................	95
Item 14	Principal Accounting Fees and Services.................................................................................................................................	95
Part IV
Item 15	Exhibits and Financial Statement Schedules..........................................................................................................................	96

Part I

ITEMS 1 AND 2 BUSINESS AND PROPERTIES

In this report, "Occidental" means Occidental Petroleum Corporation, a Delaware corporation (OPC) incorporated in 1986, 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 5 Greenway Plaza, Suite 110, Houston, Texas 77046; telephone (713) 215-7000.

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 power. Additionally, the midstream and marketing segment invests in entities that conduct similar activities.

On November 30, 2014, the spin-off of Occidental's California oil and gas operations and related assets was completed through the pro rata distribution of 81.3 percent of the outstanding shares of common stock of California Resources Corporation (California Resources) to holders of Occidental common stock creating an independent, publicly traded company. The statements of income and cash flows, and supplemental oil and gas information related to California Resources have been treated as

discontinued operations for the years ended December 31, 2014, 2013 and 2012 presented in this Annual Report on Form 10-K. The assets and liabilities of California Resources were removed from Occidental's consolidated balance sheet as of November 30, 2014. Additional information related to the spin-off can be found in Item 8 Financial Statements and Supplementary Data - Note 17 to the Consolidated Financial Statements.

For information regarding Occidental's segments, geographic areas of operation and current developments, including its recent strategic review and actions related thereto, 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 in Colorado, New Mexico, North Dakota and Texas. International operations are located in Bahrain, Bolivia, Colombia, Iraq, Libya, Oman, Qatar, the United Arab Emirates (UAE) and Yemen.  

ProvedReservesandSalesVolumes

The table below shows Occidental’s total oil, NGLs and natural gas proved reserves and sales volumes in 2014, 2013 and 2012. 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 are in millions of barrels; natural gas is in billions of cubic feet (Bcf); barrels of oil equivalent (BOE) are in millions.

	2014					2013					2012
Proved Reserves	Oil	NGLs	Gas	BOE	(a)	Oil	NGLs	Gas	BOE	(a)	Oil	NGLs	Gas	BOE	(a)
United States (b)	1,273	222	1,714	1,781		1,131	204	2,012	1,670		1,069	156	1,955	1,551
International	497	140	2,413	1,038		482	134	2,711	1,068		469	116	2,679	1,031
Total	1,770	362	4,127	2,819		1,613	338	4,723	2,738		1,538	272	4,634	2,582
Sales Volumes
United States (b)	67	20	173	116		64	21	193	117		61	21	207	116
International	74	2	158	102		75	3	163	105		78	3	170	110
Total	141	22	331	218		139	24	356	222		139	24	377	226

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 under the heading "Supplemental Oil and Gas Information". Proved reserves are stated on a net basis after applicable royalties.

(a) Natural gas volumes are converted to BOE at six thousand cubic feet (Mcf) of gas per 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 for a number of years. For example, in 2014, the average prices of West Texas Intermediate (WTI) oil and New York Mercantile Exchange (NYMEX) natural gas were $93.00 per barrel and $4.34 per Mcf, respectively, resulting in an oil to gas ratio of over 20 to 1.

(b) Excludes proved reserves and sales volumes for California Resources which have been classified as discontinued operations.

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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 local, current and anticipated market conditions. Occidental competes for transportation capacity and infrastructure for the delivery of its products. 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 fields, utilizing primary and enhanced oil recovery (EOR) techniques and strategic acquisitions in areas where Occidental has a competitive advantage as a result of its current successful operations or investments in shared infrastructure. Occidental also competes to develop and produce its worldwide oil and gas reserves cost-effectively, maintain a skilled workforce and obtain quality services.

CHEMICAL OPERATIONS

General

OxyChem owns and operates manufacturing plants at 23 domestic sites in Alabama, Georgia, Illinois, Kansas, Louisiana, Michigan, New Jersey, New York, Ohio, Pennsylvania, Tennessee and Texas and at two international sites in Canada and Chile. In early 2014, OxyChem began operating a 182,500 ton-per-year chlor-alkali plant in Tennessee and, through a 50/50 joint venture with Mexichem S.A.B. de C.V., broke ground on a 1.2 billion pound-per-year ethylene cracker at the OxyChem Ingleside facility. The cracker is expected to begin operating in 2017.

Competition

OxyChem competes with numerous other domestic and foreign chemical producers. OxyChem’s market position was first or second in the United States in 2014 for the principal products it manufactures and markets. 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	3.8 million tons
Caustic soda	Pulp, paper and aluminum production	4.0 million tons
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)	2.1 billion pounds
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

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MIDSTREAM AND MARKETING OPERATIONS

General

Occidental's midstream and marketing operations primarily support and enhance its oil and gas and chemicals businesses and also provide similar services for third parties.

Competition

Occidental's midstream and marketing businesses operate in competitive and highly regulated markets. Occidental's domestic pipeline business competes with other midstream transportation companies to provide transportation services. The competitive strategy of Occidental's domestic pipeline business is to ensure that

its pipeline and gathering systems connect various production areas to multiple market locations. Transportation rates are regulated and tariff-based. Occidental maximizes the value of its transportation and storage assets by marketing its own and third-party production in the oil and gas business. Other midstream and marketing operations also support Occidental's domestic and international oil and gas and chemical operations. Occidental's marketing business competes with other market participants on exchange platforms and through other bilateral transactions with direct counterparties.

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

Location	Description	Capacity
Gas Plants
Texas, New Mexico and Colorado	Occidental- and third-party-operated natural gas gathering, compression and processing systems, and CO2 processing	2.4 billion cubic feet per day
United Arab Emirates	Natural gas processing facilities for the Al Hosn gas project.	1.0 billion cubic feet per day
Pipelines
Texas, New Mexico, and Oklahoma	Common carrier oil pipeline and storage system	720,000 barrels of oil per day 6.0 million barrels of oil storage 2,900 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	18,900 miles of pipeline and gathering systems (b) Storage for 125 million barrels of oil and other petroleum products and 97 billion cubic feet of natural gas (b)
Marketing and Trading
Texas and Singapore	Trades around its assets, including transportation and storage capacity, and purchases, markets and trades oil, NGLs, gas and power	Not applicable
Power Generation
Texas and Louisiana	Occidental-operated power and steam generation facilities	1,200 megawatts per hourand 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.

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CAPITAL EXPENDITURES

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

EMPLOYEES

Occidental employed approximately 11,700 people at December 31, 2014, 7,400 of whom were located in the United States. Occidental employed approximately 7,500 people in the oil and gas and midstream and marketing segments and 3,100 people in the chemical segment. An additional 1,100 people were employedin administrative and headquarters functions. Approximately 800 U.S.-based employees and 1,200 foreign-based employees are represented by labor unions.

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 Policies, board-committee charters and Code of Business Conduct.

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

ITEM 1A    RISK FACTORS

Volatile global and local commodity pricing strongly affect 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 NGLs, and its chemical products.

Prices for crude oil, natural gas and NGLs fluctuate widely. Historically, the markets for crude oil, natural gas, NGLs and refined products have been volatile and may continue to be volatile in the future. Prolonged or further declines in crude oil, natural gas and NGLs prices would reduce Occidental's operating results and cash flows, and could impact its future rate of growth and further impact the recoverability of the carrying value of its assets.

Prices are set by global and local market forces which are not in Occidental's control. These factors include, among others:

Ø Worldwide and domestic supplies of, and demand for, crude oil, natural gas, NGLs and refined products.

Ø The cost of exploring for, developing, producing, refining and marketing crude oil, natural gas, NGLs and refined products.

Ø Operational impacts such as production disruptions, technological advances and regional market conditions, including available transportation capacity and infrastructure constraints in producing areas.

Ø Changes in weather patterns and climatic changes.

Ø The impacts of the members of OPEC and other producing nations to agree to and maintain production levels.

Ø The worldwide military and political environment, uncertainty or instability resulting from an escalation or outbreak of armed hostilities or acts of terrorism in the United States, or elsewhere.

Ø The price and availability of alternative and competing fuels.

Ø Domestic and foreign governmental regulations and taxes.

Ø Additional or increased nationalization and expropriation activities by foreign governments.

Ø General economic conditions worldwide.

The long-term effects of these and other conditions on the prices of crude oil, natural gas, NGLs and refined products are uncertain. Generally, Occidental's policy is to remain exposed to market prices of commodities; however, management may elect to hedge the price risk of crude oil, natural gas, NGLs and refined products in the future.

Recent global economic and political conditions have driven oil and gas prices down significantly. These conditions may continue for an extended period. Continued reductions in commodity prices could require us to further reduce capital spending, share repurchases, debt reduction, and impair the carrying value of assets.

The prices 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 restructuring activities may affect its stock price.

Occidental has performed a strategic review of its operations, which resulted in the restructuring and the separation or divestiture of various assets. This activity and further implementation of the strategic review may affect the market value of Occidental's common stock. For example, Occidental may take different actions than expected, receive less proceeds or retain more liabilities than anticipated in connection with any divestitures.

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

Occidental bears the risks of equipment failures, construction delays, escalating costs or competition for services, materials, supplies or labor, property or border

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disputes, disappointing drilling results or 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 and 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 federal, state, local and foreign 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 well stimulation techniques such as hydraulic fracturing and acidization), labor and employment, taxes, royalty rates, permitted production rates, entitlements, import, export and use of raw materials, equipment or products, use or increased use of land, water and other natural resources, safety, security and environmental protection, all of which may restrict or prohibit activities of Occidental or its contractors, increase Occidental's costs or reduce demand for Occidental's products;

Ø refusal of, or delay in, the extension or grant of exploration, development or production contracts; and

Ø development delays and cost overruns due to approval delays for, or denial of, drilling and other permits.

Occidental has and may continue to experience adverse consequences, such as risk of loss or production limitations, because certain of its international operations are located in countries affected by political instability, nationalizations, corruption, 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 or revenue comes from international sources.

Occidental's oil and gas business operates in highly competitive environments, which affect, among other things, its ability to make acquisitions to grow production and replace reserves.

Results of operations, reserves replacement and growth in oil and gas production depend, in part, on Occidental’s ability to profitably acquire 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. In addition, during periods of low product prices, any cash conservation efforts may delay production growth and reserve replacement efforts.

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

Concerns about climate change may affect Occidental’s operations.

Occidental could face risks of project execution, increased costs and taxes and lower demand for and restrictions or prohibition on the use of its products as a result of 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, or to increase the use of renewable or alternative energy sources. The uncertain outcome and timing of existing and proposed international, national and state GHG measures make it difficult to predict any business impact.

Occidental’s businesses may experience catastrophic events.

The occurrence of events, such as hurricanes, floods, droughts, earthquakes, other acts of nature, 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.

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Occidental's oil and gas reserve additions may not continue at the same rate and may not be fully comparable to that of other companies.

Management expects improved recovery, extensions and discoveries to continue as main sources for reserve additions but factors, such as geology, government regulations and permits and the effectiveness of development plans, are partially or fully outside management's control and could cause results to differ materially from expectations.  

Other risk factors.

Additional discussion of risks and uncertainties related to price and demand, litigation, environmental matters, oil and gas reserves estimation processes, 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 and Marketing Segment — Industry Outlook," "— Lawsuits, Claims and Contingencies," "— Environmental Liabilities and Expenditures," "— Critical Accounting Policies and Estimates," "— Quantitative and Qualitative Disclosures About 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 not received any written comments from the SEC staff that were issued 180 days or more preceding December 31, 2014 and that remain unresolved.

ITEM 3    LEGAL PROCEEDINGS

In the fourth quarter of 2014, the U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration sent a notice to an OPC subsidiary that it is seeking penalties of $165,900 related to a routine, comprehensive inspection of the subsidiary's records, procedures and facilities, covering a multi-year period. The subsidiary is contesting these penalties.

In the third quarter of 2014, the U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration sent a notice to an OPC subsidiary that it is seeking penalties of $165,600 related to a crude oil pipeline incident in Scurry County, Texas.  The subsidiary is contesting these proposed penalties.  In the second quarter of 2014, the U.S. Environmental Protection Agency and the Pennsylvania Department of Environmental Protection notified an OPC subsidiary that they are seeking penalties regarding the leak detection and repair program to control air emissions at a facility in Petrolia, Pennsylvania. The subsidiary is cooperating with the agencies to resolve the foregoing claim.

For information regarding other legal proceedings, see the information under the caption "Lawsuits, Claims and 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.

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EXECUTIVE OFFICERS

The current term of office of each executive officer of Occidental will expire at the May 1, 2015, organizational meeting of the Board of Directors or when a successor is selected. The following table sets forth the executive officers of Occidental:

Name Current Title	Age at February 23, 2015	Positions with Occidental and Subsidiaries and Employment History
Stephen I. Chazen Chief Executive Officer and President	68	Chief Executive Officer since 2011 and President since 2007; Chief Operating Officer, 2010-2011; Chief Financial Officer, 1999-2010; Director since 2010.
Willie C.W. Chiang Executive Vice President	54	Executive Vice President, Operations since 2012; Conoco Phillips: Senior Vice President, Refining, Marketing, Transportation and Commercial, 2011-2012; Senior Vice President, Refining, Marketing, Transportation, 2008-2011.
Vicki A. Hollub Executive Vice President	55	Executive Vice President since 2015, Vice President, 2013-2015; Occidental Oil & Gas Corporation: Oxy Oil & Gas: President - Americas since 2014, Executive Vice President - U.S. Operations, 2013-2014, Executive Vice President - California Operations, 2012-2013; Oxy Permian: President & General Manager, 2011-2012, Operations Manager, 2009-2011.
Edward A. “Sandy” Lowe Executive Vice President	63	Executive Vice President since 2015, Vice President, 2008-2015; Occidental Oil & Gas Corporation: Oxy Oil and Gas International: President since 2009, Executive Vice President, 2008-2009.
Marcia E. Backus Senior Vice President	60	Senior Vice President, General Counsel, Chief Compliance Officer and Corporate Secretary since 2015, Vice President, General Counsel and Corporate Secretary 2014, Vice President and General Counsel 2013; Vinson & Elkins: Partner, 1990-2013.
Christopher G. Stavros Senior Vice President	51	Senior Vice President & Chief Financial Officer since 2015, Executive Vice President and Chief Financial Officer 2014, Vice President, Investor Relations & Treasurer, 2012-2014, Vice President, Investor Relations, 2006-2012.
Cynthia L. Walker Senior Vice President	38	Senior Vice President, Strategy & Development since 2015, Executive Vice President, Strategy & Development 2014, Executive Vice President & Chief Financial Officer, 2012-2014; Goldman, Sachs & Co.: Managing Director, 2010-2012, Vice President, 2005-2010.
Jennifer M. Kirk Vice President	40	Vice President, Controller and Principal Accounting Officer since July 2014; Occidental Oil & Gas Corporation: Controller, 2008-2014.

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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 28,000 stockholders of record at January 31, 2015, and by approximately 700,000 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 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 $0.72 for each quarter of 2014 ($2.88 for the year). On February 11, 2015, a quarterly dividend of $0.72 per share was declared on the common stock, payable on April 15, 2015 to stockholders of record on March 10, 2015. The current annual dividend rate of $2.88 per share has increased by 476 percent since 2002. 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.

SHARE REPURCHASE ACTIVITIES

Occidental’s share repurchase activities for the year ended December 31, 2014, were as follows:

Period	Total Number of Shares Purchased			Average Price Paid per Share			Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs		Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs
First Quarter 2014		10,525,000			$	93.52		10,525,000
Second Quarter 2014		6,036,044	(a)		$	99.67		5,915,000
Third Quarter 2014		4,666,976	(a)		$	99.72		4,555,000
October 1-31, 2014		100,000			$	94.46		100,000
November 1-30, 2014		—			$	—		—
December 1-31, 2014		4,695,000			$	79.23		4,695,000
Fourth Quarter 2014		4,795,000			$	79.55		4,795,000
Total 2014		26,023,020			$	93.49		25,790,000		71,176,168	(b)

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

(b) Represents the total number of shares remaining at year end under Occidental's share repurchase program of 185 million shares. The program was initially announced in 2005. The program does not obligate Occidental to acquire any specific number of shares and may be discontinued at any time.

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PERFORMANCE GRAPH

The following graph compares the yearly percentage change in Occidental’s cumulative total return on its common stock with the cumulative total return of the Standard & Poor's 500 Stock Index (S&P 500) and with that of Occidental’s peer group over the five-year period ended on December 31, 2014. 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, Marathon Oil Corporation, Total S.A. and Occidental.

	12/31/2009		12/31/2010		12/31/2011		12/31/2012		12/31/2013		12/31/2014
	$	100	$	123	$	120	$	100	$	128	$	117
		100		113		123		126		154		144
		100		115		117		136		180		205

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

_______________________

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

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ITEM 6 SELECTED FINANCIAL DATA

FIVE-YEAR SUMMARY OF SELECTED FINANCIAL DATA

(in millions, except per-share amounts)

As of and for the years ended December 31,	2014			2013				2012				2011			2010
RESULTS OF OPERATIONS (a)
Net sales	$	19,312		$	20,170			$	20,100			$	20,001		$	16,129
Income (loss) from continuing operations	$	(130	)	$	4,932			$	3,829			$	5,527		$	3,851
Net income attributable to common stock	$	616		$	5,903			$	4,598			$	6,771		$	4,530
Basic earnings per common share from continuing operations	$	(0.18	)	$	6.12			$	4.72			$	6.79		$	4.65
Basic earnings per common share	$	0.79		$	7.33			$	5.67			$	8.32		$	5.57
Diluted earnings per common share	$	0.79		$	7.32			$	5.67			$	8.32		$	5.56
FINANCIAL POSITION (a)
Total assets	$	56,259		$	69,443			$	64,210			$	60,044		$	52,432
Long-term debt, net	$	6,838		$	6,939			$	7,023			$	5,871		$	5,111
Stockholders’ equity	$	34,959		$	43,372			$	40,048			$	37,620		$	32,484
MARKET CAPITALIZATION (b)	$	62,119		$	75,699			$	61,710			$	75,992		$	79,735
CASH FLOW FROM CONTINUING OPERATIONS
Operating:
Cash flow from operations	$	8,871		$	10,229			$	9,050			$	9,740		$	7,498
Investing:
Capital expenditures	$	(8,930	)	$	(7,357	)		$	(7,874	)		$	(5,354	)	$	(2,884	)
Cash provided (used) by all other investing activities, net	$	2,686		$	1,040			$	(1,989	)		$	(3,530	)	$	(4,476	)
Financing:
Cash dividends paid	$	(2,210	)	$	(1,553	)	(c)	$	(2,128	)	(c)	$	(1,436	)	$	(1,159	)
Purchases of treasury stock	$	(2,500	)	$	(943	)		$	(583	)		$	(274	)	$	(67	)
Cash provided (used) by all other financing activities, net	$	2,384		$	(437	)		$	1,865			$	535		$	2,309
DIVIDENDS PER COMMON SHARE	$	2.88		$	2.56			$	2.16			$	1.84		$	1.47
WEIGHTED AVERAGE BASIC SHARES OUTSTANDING (millions)	781			804				809				812			812

Note:  Argentine operations were sold in February 2011 and are presented as discontinued operations. The statements of income and cash flows related to California Resources have been treated as discontinued operations for all years presented. The assets and liabilities of California Resources were removed from Occidental's consolidated balance sheet as of November 30, 2014.

(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) 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.

(c) The 2012 amount includes an accelerated fourth quarter dividend payment, which normally would have been accrued as of year-end 2012 and paid in the first quarter of 2013.

ITEM 7

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. 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 power. Additionally, the midstream and marketing segment invests in entities that conduct similar activities.

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STRATEGY

General

Through its operations, Occidental aims to maximize total returns to stockholders using the following strategies:

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

Ø Focus on lowering finding and developing, production and maintenance costs;

Ø Allocate and deploy capital with a focus on achieving returns well in excess of its cost of capital;

Ø Maintain financial discipline and a strong balance sheet; and

Ø Provide consistent dividend growth.

In conducting its business, Occidental accepts commodity, engineering and limited exploration risks. Capital is employed to operate all assets in a safe and environmentally sound manner. Occidental seeks to limit its financial and political risks.

The fourth quarter of 2014 saw a sharp decline in oil and NGLs prices. Price volatility is inherent in the oil and gas business, and in order to manage this risk, Occidental maintains a low debt to capitalization ratio and retains sufficient cash on hand. Occidental will focus on lowering its costs which over time management believes will correlate to increasing and decreasing oil prices.

With respect to the strategic initiatives announced last year, Occidental has:

Ø Completed the separation of its California assets, leading to the creation of California Resources Corporation (California Resources), an independent, publicly traded company;

Ø Sold its interests in the Hugoton Field, resulting in proceeds of $1.3 billion;

Ø Sold a portion of its interest in Plains GP Holdings (Plains Pipeline) for proceeds of $1.7 billion while continuing to hold an approximate 13 percent interest; and

Ø Sold its interest in the BridgeTex pipeline, resulting in proceeds of $1.1 billion while maintaining access to United States gulf markets through this pipeline.

As a result of these strategic initiatives, Occidental ended the year with $7.8 billion in total cash, cash equivalents and restricted cash, which exceeds its long-term debt of $6.8 billion.

The following describes the application of Occidental’s overall strategy to each of its operating segments:

Oil and Gas

The oil and gas business implements Occidental's strategy primarily by:

Ø Operating and developing areas where reserves are known to exist and to increase production from core areas, primarily in the Permian Basin and parts of the Middle East;

Ø Using enhanced oil recovery techniques, such as CO₂, water andsteam floods, in mature fields;

Ø Focusing a sizable portion of Occidental's drilling activities on unconventional opportunities, primarily in the Permian Basin; and

Ø Maintaining a disciplined approach towards domestic acquisitions and divestitures and the execution of international contracts, with an emphasis on creating value and further enhancing Occidental's existing positions.

Over the past several years, Occidental built a large portfolio of growth-oriented assets in the United States. In 2014, Occidental spent a much larger portion of its investment capital on the development of this portfolio. Acquisitions in 2014 were approximately $1.6 billion, and comprised mainly of Permian Basin properties. This acquisition activity reflects Occidental's strategy to capitalize on the opportunities presented by its existing portfolio of assets and strong balance sheet.

Management believes Occidental's oil and gas segment growth will occur primarily through exploitation and development opportunities in the Permian Basin and focused international projects in the Middle East.

Chemical

The primary objective of OxyChem is to generate cash flow in excess of its normal capital expenditure requirements and achieve above-cost-of-capital returns. The chemical segment's strategy is to be a low-cost producer in order to maximize its cash flow generation. OxyChem concentrates on the chlorovinyls chain beginning with chlorine, which is co-produced with caustic soda, 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 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. In early 2014, OxyChem completed construction and began operating a 182,500 ton-per-year membrane chlor-alkali plant in Tennessee and, through a 50/50 joint venture with Mexichem S.A.B. de C.V., broke ground on a 1.2 billion pound-per-year ethylene cracker at the OxyChem Ingleside facility. The joint venture provides an opportunity to capitalize on the advantage that U.S. shale gas development has presented to U.S. chemical producers by providing low-cost ethane as a raw material

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and is expected to begin operating in 2017. In the third quarter, OxyChem completed construction and began operating a 162,000 tons per year hydrochloric acid synthesis unit at its existing Niagara Falls, N.Y. facility.

Midstream and Marketing

The midstream and marketing segment strives to maximize realized value by optimizing use of its assets, including its transportation and storage capacity, and by providing access to multiple markets. In order to generate returns, the segment evaluates opportunities across the value chain and uses its assets to provide services to other Occidental segments as well as third parties. 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, while limiting credit risk exposure. Capital is employed to sustain or, where appropriate, increase operational and transportation capacity and to improve the competitiveness of Occidental's assets. During 2014, Occidental sold its interest in BridgeTex Pipeline while retaining access to United States gulf markets through the pipeline, resulting in a $633 million pre-tax gain. The BridgeTex Pipeline transports crude oil between the Permian region and the United States gulf coast refinery markets and began service in the second half of 2014. Simultaneously with the sale of Occidental's interest in the BridgeTex Pipeline, Occidental completed the sale of a portion of its investment in Plains Pipeline, resulting in a $1.4 billion pre-tax gain.

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 Total Shareholder Return;

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

Ø Dividend growth;

Ø Segment specific measures such as per-unit profit, production cost, cash flow, finding and development costs and reserves replacement percentages; and

Ø Health, environmental, safety and process metrics.

Debt Structure

In 2014, Occidental decreased its debt balance by $101 million. The debt-to-capitalization (debt and equity) ratio was 16 percent and 14 percent as of December 31, 2014 and 2013, respectively.

OIL AND GAS SEGMENT

Oil and gas information related to California Resources have been treated as discontinued operations for all periods presented.

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 2014 and 2013:

	2014		2013
WTI oil ($/barrel)	$	93.00	$	97.97
Brent oil ($/barrel)	$	99.51	$	108.76
NYMEX gas ($/Mcf)	$	4.34	$	3.66

The following table presents Occidental's average realized prices as a percentage of WTI, Brent and NYMEX for 2014 and 2013:

	2014		2013
Worldwide oil as a percentage of average WTI	97	%	101	%
Worldwide oil as a percentage of average Brent	91	%	91	%
Worldwide NGLs as a percentage of average WTI	40	%	39	%
Domestic natural gas as a percentage of NYMEX	91	%	88	%

Average worldwide realized oil prices fell $8.68, or 9 percent, in 2014 compared to 2013. Approximately half of Occidental’s oil production tracks world oil prices, such as Brent, and half tracks WTI. The average realized domestic natural gas price in 2014 increased 23 percent from 2013. The WTI and Brent oil price indexes declined significantly in the fourth quarter of 2014, settling at $53.27 per barrel and $57.33 per barrel, respectively, as of December 31, 2014. The WTI and Brent oil price indexes settled at $98.42 per barrel and $110.80 per barrel, respectively, as of December 31, 2013.

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

Operations

Domestic Interests

Occidental conducts its domestic operations through land leases, subsurface mineral rights it owns or a combination of both surface land and subsurface mineral rights it owns. Occidental's domestic oil and gas leases have a primary term ranging from one to ten years, which is extended through the end of production once it commences. Of the total 4.5 million net acres in which Occidental has interests, approximately 87 percent is leased, 12 percent is owned subsurface mineral rights and 1 percent is owned land with mineral rights.

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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, 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:

• Excludes volumes from the Argentine operations sold in 2011 and California Resources which was separated on November 30, 2014 into a separate publicly traded company. Both operations have been reflected as discontinued operations for all applicable periods.

• Includes Hugoton (sold in April 2014) average daily production volumes of 6MBOE, 18MBOE, 19MBOE, 20MBOE and 22MBOE for 2014, 2013, 2012, 2011 and 2010, respectively.

• Includes average daily production of 5MBOE for 2010 related to a noncontrolling interest in a Colombian subsidiary.

United States Assets

United States

1. Permian Basin

2. Midcontinent and Other interests

Permian Basin

Occidental's Permian Basin production is diversified across a large number of producing areas. The 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 16 percent of the total United States oil production. Occidental is the largest operator and the largest producer of oil in the Permian Basin with an approximate 13 percent net share of the total oil production in the basin. Occidental also produces and processes natural gas and NGLs in the basin.

Occidental manages its Permian Basin operations through two business units: Permian Resources, which includes growth-oriented unconventional opportunities and Permian EOR (enhanced oil recovery), which utilizes enhanced oil recovery techniques such as; CO₂ floods and waterfloods. During 2014, capital efficiency efforts reduced drilling costs per well by 8 percent for the Permian Basin operations. In addition, management began transitioning to a horizontal drilling program to take advantage of shale and other unconventional opportunities. In the Permian Basin, Occidental spent over $2.6 billion of capital in 2014 with 73 percent spent on Permian Resources assets. In 2015, Permian Basin capital spending is expected to be approximately $2.2 billion. Approximately 78 percent of the total capital to be spent in the Permian Basin is planned for Permian Resources assets to focus on growing oil production.

Occidental's Permian Resources operations are among its fastest-growing assets and held approximately 2.5 million net acres at the end of 2014, including acreage with prospective resource potential. The development program, largely began in 2010, continued to increase in 2014, accounting for 280 wells drilled. In 2014, Permian Resources drilled 167 horizontal wells and expects to drill the same number of horizontal wells in 2015. Permian Resources has a sizeable inventory of wells to develop with economic returns in a low price environment. Continued completion optimization, the application of enhanced manufacturing principles, combined with expected commercial savings is expected to increase the well inventory even further. Production from this business unit comes from approximately 13,000 gross wells, of which 61 percent are operated by other producers. On a net basis,

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this represents approximately 5,500 wells, of which only 22 percent are operated by others.

Permian EOR operates a combination of CO₂ floods and waterfloods which have similar development characteristics and ongoing monitoring and maintenance requirements. Due to a unique combination of characteristics, the Permian Basin has been a leader in the implementation of CO₂ enhanced oil recovery projects. The Permian Basin’s concentration of large conventional reservoirs, favorable CO₂ flooding performance and the proximity to naturally occurring CO₂ supply has resulted in decades of steady growth in enhanced oil production. With over 30 active floods and 40 years of experience, Permian EOR is the industry leader in Permian Basin CO₂ flooding.

Numerous projects have demonstrated that CO₂ injection can increase the recovery from Permian Basin reservoirs by more than 25 percent. Significant opportunity remains to expand Occidental's existing projects into new portions of reservoirs. Occidental operates reservoirs that thus far have only been water flooded, leaving opportunity for significant additional recovery with new CO₂ injection. Hence, even small improvements in recovery efficiency can add significant reserves. Technology improvements, such as the recent trend towards vertical expansion of the CO₂ flooded interval into residual oil zone targets continue to yield more recovery from existing projects. Over the last few years, Occidental has had an ongoing program of deepening wells, with 109 wells deepened in 2014 and 81 wells planned in 2015. Occidental utilizes work-over rigs to drill the extra depth into additional CO₂ floodable sections of the reservoir. These are low cost projects which can add reserves even in a low price environment. Permian EOR has a large inventory of future CO₂ projects which could be developed over the next 20 years or accelerated, depending on market conditions.

The current strategy for Permian EOR is to invest sufficient capital to maintain current production thereby providing cash flow after capital to support growth in Permian Resources. By exploiting natural synergies between Permian EOR and Permian Resources, Occidental is able to deliver unique advantages, efficiencies and expertise across its Permian Basin operations. Occidental's share of production in the Permian Basin was approximately 222,000 BOE per day in 2014 with 75,000 BOE per day coming from Permian Resources and 147,000 BOE per day from Permian EOR.

Midcontinent and Other

In April 2014, Occidental sold its Hugoton Field operations in Kansas, Oklahoma, and Colorado for $1.3 billion and recorded a pre-tax gain on the sale of $531 million.

The remaining Midcontinent and Other properties include interests in the Williston Basin, the Piceance Basin, the Eagle Ford Shale and other areas in South Texas. These properties are located in North Dakota, Colorado, and Texas. Occidental holds approximately 303,000 net acres of oil-producing and unconventional properties in the Williston Basin's Bakken, Three Forks and Pronghorn formations, as well as approximately 187,000 net acres in

the Piceance area and 174,000 net acres in South Texas, including 4,000 net acres in the Eagle Ford Shale.

In Midcontinent and Other, excluding Hugoton Field operations, Occidental drilled approximately 99 wells and produced approximately 90,000 BOE per day in 2014.

Other Developments

During the fourth quarter of 2014, commodity prices declined significantly causing Occidental to assess the carrying value of its domestic producing assets and assess development plans for its non-producing assets. In the fourth quarter of 2014, Occidental recorded pre-tax impairment charges of $2.7 billion in the Williston Basin, $904 million related to its gas and NGLs assets and $589 million for other domestic acreage. In the second quarter of 2014, Occidental also recorded a pre-tax impairment charge of $471 million for certain non-producing domestic acreage that management decided not to pursue. Any further sustained declines in commodity prices may result in additional impairments in the future.

Middle East/North Africa Assets

Middle East/North Africa

1. Bahrain

2. Iraq

3. Libya

4. Oman

5. Qatar

6. United Arab Emirates

7. Yemen

Bahrain

In 2009, Occidental and 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 50 percent from an initial level of 1.5 billion cubic feet per day to over 2.3 billion cubic feet per day and increased gross oil production from 26,000 barrels per day to more than 44,000 barrels per day. Occidental's share of production from Bahrain during 2014 was approximately 236 million cubic feet (MMcf) of gas per day and 4,000 barrels of oil per day.

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Occidental has been pursuing opportunities to adjust terms of the DPSA to more accurately reflect current operating and economic challenges under the contract. However, Occidental has not yet been successful in obtaining these concessions. Due to deteriorating market conditions, Occidental has recorded a pre-tax impairment charge of $801 million for its investments in Bahrain.

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. In 2013, the terms were improved reflecting a reduction in the targeted production level to 850,000 BOE per day and a five-year extension to 2035. Occidental's interest in this contract entitles Occidental to receive oil for cost recovery and a remuneration fee. Delays in implementation of development plans have limited the amount of production from Iraq. Occidental does not know when development activities will reach desired levels. Occidental's share of production from Iraq was approximately 13,000 BOE per day in 2014.

Libya

Occidental participates with the Libyan National Oil Company in the Sirte Basin producing operations. These agreements continue through 2032. In 2014, Occidental suspended exploration activities due to civil unrest in the country. Production disruptions continued throughout 2014 due to oil field and export terminal strikes and closures. Occidental does not know when operations will return to normal levels. The 2014 production volumes were insignificant.

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.

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

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 2014, Occidental had drilled more than 2,400 new wells and continued implementation of a major steamflood project. In 2014, the average gross daily production was 122,000 BOE per day, which was over 15 times higher than the production rate in September 2005 when Occidental assumed operations.

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. In 2014, Occidental signed a five year extension for the initial phase for the discovered non associated gas area (natural gas not in contact with crude oil in a reservoir) for Block 62.

Occidental's share of production from Oman was approximately 76,000 BOE per day in 2014.

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 2014, Occidental continued to develop the ISND field to improve ultimate recovery in all existing contract reservoirs.

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 operates a pipeline and is discussed further in "Midstream and Marketing Segment - Pipeline Transportation."

Occidental's share of production from Qatar was approximately 107,000 BOE per day in 2014.

United Arab Emirates

In 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. Once fully operational, the project is anticipated to produce over 450 MMcf per day of natural gas and 75,000 barrels per day of NGLs and condensate, of which Occidental’s net share would be over 180 MMcf per day and 30,000 barrels per day, respectively. Initial start up of production from this project commenced in January 2015 and is proceeding as planned.

Additionally, the Al Hosn gas project includes gas processing facilities which are discussed further in "Midstream and Marketing Segment - Gas Processing Plants and CO₂ Fields and Facilities".

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 December 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.

Given the political instability and civil unrest in Yemen, production levels may be unpredictable for the remainder of the Block 10 contract term and it is unlikely the contract will be extended. Occidental's share of production from the Yemen properties was approximately 10,000 BOE per day in 2014.

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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. Occidental's share of production from Bolivia was 2,000 BOE per day in 2014.

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 27,000 BOE per day in 2014.

Proved Reserves

Proved oil, NGLs 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, NGLs 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 2014, 2013 and 2012 disclosures, the calculated average West Texas Intermediate oil prices were $94.99, $96.94 and $94.71 per barrel, respectively. The calculated average Brent oil prices for 2014, 2013 and 2012 disclosures were $99.51, 108.76, and $111.70 per barrel, respectively. The calculated average Henry Hub gas prices for 2014, 2013 and 2012 were $4.42, $3.65 and $2.79 per MMBtu, respectively.

Occidental had proved reserves at year-end 2014 of 2,819 million BOE, compared to the year-end 2013 amount of 2,738 million BOE. Proved reserves at year-end 2014 and 2013 consisted of, respectively, 63 percent and 59 percent oil, 13 percent and 12 percent NGLs and 24 percent and 29 percent natural gas. Proved developed reserves represented approximately 71 percent and 70 percent, respectively, of Occidental’s total proved reserves at year-end 2014 and 2013.

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 380 million BOE in 2014, and included 337 million BOE from Occidental's development program net of revisions of prior estimates, and 43 million BOE from purchases.

The total additions were as follows:

(in millions of BOE)
Improved recovery	354
Extensions and discoveries	41
Purchases	43
Revisions of previous estimates	(58	)
Total additions	380

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 management’s control, and will affect whether these historical sources of proved reserve additions continue at similar levels. Occidental's 2014 development program provided approximately 265 million BOE of reserve additions domestically.

Improved Recovery

In 2014, Occidental added proved reserves of 354 million BOE from improved recovery through its EOR and infill drilling activities. Generally, the improved recovery additions in 2014 were mostly associated with the continued development of properties in the Permian Basin. These properties comprise both conventional projects, which are characterized by the deployment of EOR development methods, largely employing application of CO₂ flood, waterflood or steam flood, and unconventional projects. These types of conventional EOR development methods can be applied through existing wells, though additional drilling is frequently 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. The use of either CO₂ or steam flooding depends on the geology of the formation, the evaluation of engineering data, availability and cost of either CO₂ or steam and other economic factors. Both techniques work similarly to lower viscosity causing the oil to move more easily to the 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.

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Extensions and Discoveries

Occidental also added proved reserves from extensions and discoveries, which are dependent on successful exploration and exploitation programs. In 2014, extensions and discoveries added 41 million BOE related primarily to the recognition of proved undeveloped reserves from the Permian Basin and Oman.

Purchases 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 2014, Occidental added 43 million BOE through purchases of proved reserves largely consisting of domestic acquisitions mainly in the Permian Basin.

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 2014, revisions of previous estimates provided a decrease of 58 million BOE to proved reserves. Occidental had positive technical revisions of 7 million BOE which exclude the impact of negative revisions in Bahrain of 54 million BOE and price revisions of 11 million BOE.

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.

Proved Undeveloped Reserves

In 2014, Occidental had proved undeveloped reserve additions of 328 million BOE from improved recovery, extensions and discoveries and purchases. Of the total additions, 284 million BOE represented additions from improved recovery, primarily in the Permian Basin. Occidental added 15 million BOE through domestic acquisitions, mainly in the Permian Basin. Additionally, the proved undeveloped reserves increased 29 million BOE due to extensions and discoveries mainly in Oman and the Permian Basin. These proved undeveloped reserve additions were offset by transfers of 315 million BOE to the proved developed category as a result of the 2014 development programs including 214 million BOE from Al Hosn gas project reserves. Occidental incurred approximately $1.7 billion in 2014 to convert proved undeveloped reserves to proved developed reserves. Al Hosn, Permian Basin, Oman, Williston Basin and South Texas accounted for approximately 93 percent of the

reserve transfers from proved undeveloped to proved developed in 2014. A substantial portion of the proved undeveloped reserves as of December 31, 2014 was the result of the development program in the Permian Basin, which represents 55 percent of total year-end proved undeveloped reserves.

Recent global economic conditions have driven oil and gas prices down significantly. These conditions may continue for an extended period. Prolonged or further declines in commodity prices could require Occidental to further reduce capital spending, potentially impacting either the quantity or the development timing of proved undeveloped reserves.

Reserves Evaluation and Review Process

Occidental's estimates of proved reserves and associated future net cash flows as of December 31, 2014, 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 reserve volumes are estimated by a forecast of production rates, operating costs and capital expenditures. Price differentials between benchmark prices (the unweighted arithmetic average of the first-day-of-the-month price for each month within the year) and realized prices and specifics of each operating agreement are then used to estimate the net reserves. Production rate forecasts are derived by a number of methods, including estimates from decline curve analysis, type-curve analysis, material balance calculations that take into account the volumes of substances replacing the volumes produced and associated reservoir pressure changes, seismic analysis and computer simulation of the reservoir performance. These field-tested technologies have demonstrated reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. Operating and capital costs are forecast using the current cost environment applied to expectations of future operating and development activities.

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

The current Senior Vice President, Reserves for Oxy Oil and Gas is responsible for overseeing the preparation of reserve estimates, in compliance with U.S. Securities and Exchange Commission (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

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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 2014, Ryder Scott conducted a process review of the 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, 2014, in accordance with the 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 2014 year-end total proved reserves portfolio. In 2014, Ryder Scott reviewed approximately 24 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 72 percent of Occidental’s existing proved oil and gas reserves. Management retains Ryder Scott to provide objective third-party input on its methods and procedures and to gather industry information applicable to Occidental’s reserve estimation and reporting process. Ryder Scott has not been engaged to render an opinion as to the reasonableness of reserves quantities reported by Occidental. Occidental has filed Ryder Scott's independent report as an exhibit to this Form 10-K.

Based on its reviews, including the data, technical processes and interpretations presented by Occidental, Ryder Scott has concluded that the overall procedures and methodologies Occidental utilized in estimating the proved reserves volumes, 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 current SEC regulations.

Industry Outlook

The petroleum industry is highly competitive and subject to significant volatility due to various market conditions. The WTI and Brent oil price indexes declined significantly in the fourth quarter of 2014, settling at $53.27 per barrel and $57.33 per barrel from $98.42 per barrel and $110.80 per barrel, respectively, as of December 31, 2014 and 2013.

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) transportation capacity, infrastructure constraints, and cost in producing areas; (iii) currency exchange rates; and (iv) the effect of changes in these variables on market perceptions.

NGLs 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.

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 make it impossible to predict the future direction of oil, NGLs and domestic gas prices reliably. International gas prices are generally fixed under long-term contracts. Occidental continues to respond 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.

CHEMICAL SEGMENT

Business Environment

The modest pace of United States economic growth resulted in slightly higher demand for domestically produced energy and feedstocks. Chlorovinyl margins were challenged throughout the year as unprecedented unplanned and planned ethylene cracker outages significantly affected the supply of ethylene resulting in historically high ethylene prices. Chemical segment earnings, excluding asset impairments in 2014 and the gain on sale of the investment in Carbocloro in 2013, decreased in 2014, primarily due to higher energy and ethylene costs and lower chlor-alkali pricing driven by continued unfavorable supply and demand fundamentals.

Business Review

Basic Chemicals

During 2014, the United States economy continued its slow recovery with full-year growth expected to show only a slight improvement from the prior year. The improvement to the economy contributed to moderate improvements in domestic chemical demand. Despite the commissioning of three chlor-alkali plants in the U.S., including OxyChem’s 182,500 ton-per-year membrane plant in Tennessee, industry chlorine operating rates remained relatively flat

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with 2013 at approximately 84 percent, which resulted in chlorine prices ending approximately 6 percent below where they began. Exports of downstream chlorine derivatives into the vinyls chain were competitive for the first half of 2014 but were negatively impacted by a significant increase in ethylene prices as third quarter supply was restricted by historically high ethylene cracker plant outages. Liquid caustic soda prices experienced downward price pressure during the first quarter as the industry absorbed the additional chlor-alkali capacity that came on-line. Export demand and pricing remains under pressure due to global over capacity and lower growth in major consuming regions such as Latin American and Asia. Businesses such as calcium chloride, potassium hydroxide and muriatic acid improved compared to 2013 as domestic demand improved and margins remained stable throughout the year.

Vinyls

Domestic PVC demand in 2014 grew by approximately 3 percent compared to 2013 as the housing and commercial construction markets continued their recovery. Despite the improvement in the domestic market, the industry operating rate decreased by slightly more than 2 percent due to a combination of industry outages early in 2014 and export demand declining by approximately 10 percent compared to the prior year. Industry margins improved in 2014 due to first quarter PVC price increases, which were partially offset by higher ethylene prices. During the first half of 2014, North America ethane-based ethylene production continued to be price advantaged over Europe and Asia, but is reaching parity with the rest of the world as the price of oil declines. Despite the year-over-year reduction in North American exports of PVC, export volumes represented nearly 30 percent of total PVC sales of North American producers. Construction commenced on the Ingleside, Texas, ethylene cracker during the first half of 2014 and commercial operations are expected to begin in early 2017.

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. Long-term weakness in the petroleum industry may negatively affect the demand and pricing of a number of Occidental’s products that are consumed exclusively by industry participants.

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 2015. Overall, the increase in chlor-alkali capacity may restrict significant price improvement but anticipated higher demand from strengthening global markets coupled with lower natural gas prices should allow for moderate chlorine and caustic soda margin improvement in 2015. 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 feedstock costs in global markets.

Vinyls

North American demand and operating rates should improve in 2015 if growth in both housing starts and commercial construction continues. Occidental expects U.S. export demand to increase in 2015 and margins to improve over 2014.

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 commodities and engage in storage activities. Marketing and trading performance is affected primarily by commodity price changes and margins in oil and gas transportation and storage programs. Processing and transportation results are affected by the volumes that are processed 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 2014, excluding the gains from the sales of the BridgeTex Pipeline and a portion of an investment in Plains Pipeline, were greater than 2013, reflecting higher income from the gas processing and power generation businesses, partially offset by lower marketing performance and pipeline income.

Business Review

Marketing and Trading

The marketing and trading group markets substantially all of Occidental’s oil, NGLs and gas production, trades around its assets, including its own and third party 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 better utilize and optimize its assets. Marketing performance in 2014 declined compared to 2013 due to lower margins on crude oil and NGLs, partially offset by higher margins in natural gas. In the second half of 2014, Occidental commenced winding down its Phibro commodity trading operations. As of year-end there was no material exposure related to Phibro’s remaining activities.

Gas Processing Plants and CO₂ Fields and Facilities

Occidental processes its and third-party domestic wet gas to extract NGLs and other gas byproducts, including CO₂, and delivers dry gas to pipelines. Margins primarily result from the difference between inlet costs of wet gas and market prices for NGLs. Occidental’s 2014 earnings from these operations increased compared to 2013, due to the multiple plant turnarounds in the Permian Basin operations during 2013.

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Occidental, together with ADNOC, completed the Al Hosn gas processing facilities in Abu Dhabi at the end of 2014. The Al Hosn gas processing facilities are designed to process 1.0 bcf per day of natural gas and separate it into sales gas, condensate, NGLs and sulfur. The Al Hosn gas processing facilities includes processing and treatment facilities, sulfur recovery units, including facilities to extract sulfur from natural gas and to load and store sulfur. The project is anticipated to produce approximately 8,700 tons per day of sulfur, of which Occidental's share would be 3,500 tons of sulfur per day. The Al Hosn gas processing facilities will generate revenues from gas processing fees and the sale of sulfur.

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. Dolphin Pipeline is currently expanding gas compression facilities to achieve maximum pipeline capacity. Occidental believes substantial opportunities remain to provide gas transportation to additional customers in the region to reach the full capacity of the Dolphin Pipeline and generate additional midstream revenues and cash flows.

Occidental owns an oil common carrier pipeline and storage system with approximately 2,900 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 720,000 barrels per day, 6.0 million barrels of active storage capability and 108 truck unloading facilities at various points along the system, which allow for additional volumes to be delivered into the pipeline.

During 2014, Occidental sold its interest in BridgeTex Pipeline while retaining access to United States gulf markets through the pipeline. The BridgeTex Pipeline transports crude oil between the Permian region and the United States gulf coast refinery markets and began service in the second half of 2014. Simultaneously with the sale of Occidental's interest in the BridgeTex Pipeline, Occidental completed the sale of a portion of its investment in Plains Pipeline. Following the fourth quarter 2014 sale of a portion of its investment, Occidental owns approximately 13 percent of Plains Pipeline. The Plains Pipeline investment contributed approximately 19 percent of the segment's earnings for 2014, excluding the gain from the sale.

Occidental's 2014 pipeline transportation earnings declined from 2013 due to lower income from its investment in Plains Pipeline as a result of Occidental's lower ownership interest.

Power Generation Facilities

Earnings from power and steam generation facilities are derived from sales to affiliates and third parties and the increase in earnings in 2014 compared to 2013 was due to higher margins from higher spark spreads and production.

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 NGLs prices, which cannot reasonably be predicted. Generally, higher NGLs prices result in higher profitability. Although the marketing and trading business in isolation can be volatile in periods of severe price swings, Occidental does not expect the volatility of these operations to be significant to the company as a whole given Occidental's framework of controls and risk management. Occidental continues to actively focus on marketing its commodity production to generate maximum value for its stakeholders.

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 statements of income and cash flows, and supplemental oil and gas information related to California Resources have been treated as discontinued operations for all periods presented. The assets and liabilities of California Resources were removed from Occidental's consolidated balance sheet as of November 30, 2014.

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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,	2014			2013			2012
NET SALES(a)
Oil and Gas	$	13,887		$	15,008		$	14,953
Chemical	4,817			4,673			4,580
Midstream and Marketing	1,373			1,174			1,164
Eliminations (a)	(765		)	(685		)	(597		)
	$	19,312		$	20,170		$	20,100
EARNINGS
Oil and Gas (b)	$	428		$	6,411		$	5,840
Chemical (c)	420			743			720
Midstream and Marketing (d) (e)	2,564			1,523			440
	3,412			8,677			7,000
Unallocated corporate items
Interest expense, net	(71		)	(124		)	(141		)
Income taxes	(1,685		)	(3,214		)	(2,659		)
Other (f)	(1,800		)	(407		)	(371		)
Income (loss) from continuing operations (e)	(144		)	4,932			3,829
Discontinued operations, net	760			971			769
Net Income attributable to common stock	$	616		$	5,903		$	4,598
Basic Earnings per Common Share	$	0.79		$	7.33		$	5.67

(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) The 2014 amount includes a net $5.3 billion of pre-tax charges related to the impairments of domestic and international assets, other charges and the sale of Hugoton assets. The 2013 amount includes $607 million of pre-tax charges related to the impairment of domestic non-producing acreage. The 2012 amount includes pre-tax charges of $1.7 billion for the impairment of domestic gas assets and related items.

(c) The 2014 amount includes $149 million pre-tax charges related to impairments of chemical assets. The 2013 amount includes a $131 million pre-tax gain from the sale of an investment in Carbocloro, a Brazilian chemical facility.

(d) The 2014 amount includes a $633 million pre-tax gain from the sale of Occidental's interest in BridgeTex Pipeline Company, LLC, and a $1.4 billion pre-tax gain from the sale of an investment in Plains Pipeline. The 2013 amount includes a $1.0 billion pre-tax gain from the sale of a portion of an investment in Plains Pipeline and other items.

(e) Represents amounts attributable to common stock after deducting a non controlling interest amount of $14 million in 2014. The non controlling interest amount has been netted in the midstream and marketing segment earnings.

(f) The 2014 amount includes an $805 million pre-tax charge related to the impairment of the Joslyn oil sands project and a $553 million charge related to an other than temporary loss for retained shares of California Resources. The 2013 amount includes a $55 million pre-tax charge for the estimated cost related to the employment and post-employment benefits for Occidental's former Executive Chairman and termination of certain other employees and consulting arrangements.

Oil and Gas

(in millions)	2014		2013		2012
Segment Sales	$	13,887	$	15,008	$	14,953
Segment Earnings	$	428	$	6,411	$	5,840

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, 2014. 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	2014	2013	2012
United States
Oil (MBBL)
Permian Resources	43	35	36
Permian EOR	111	111	106
Midcontinent and Other	27	24	20
Total excluding Hugoton	181	170	162
Hugoton	2	6	5
Total	183	176	167
NGLs (MBBL)
Permian Resources	12	10	11
Permian EOR	30	29	28
Midcontinent and Other	12	15	14
Total excluding Hugoton	54	54	53
Hugoton	1	3	3
Total	55	57	56
Natural gas (MMCF)
Permian Resources	120	117	114
Permian EOR	38	40	41
Midcontinent and Other	301	315	347
Total excluding Hugoton	459	472	502
Hugoton	17	56	63
Total	476	528	565
Latin America
Oil (MBBL) – Colombia	27	29	29
Natural gas (MMCF) – Bolivia	11	12	13
Middle East/North Africa
Oil (MBBL)
Dolphin	7	6	8
Oman	69	66	67
Qatar	69	68	71
Other	28	39	40
Total	173	179	186
NGLs (MBBL)
Dolphin	7	7	8
Other	—	—	1
Total	7	7	9
Natural gas (MMCF)
Dolphin	143	142	163
Oman	43	51	57
Other	236	241	232
Total	422	434	452
Total Production excluding Hugoton	591	591	599
Hugoton	6	18	19
Total Production (MBOE) (a)	597	609	618
(See footnotes following the Average Realized Prices table)

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Sales Volumes per Day	2014	2013	2012
United States
Oil (MBBL)	183	176	167
NGLs (MBBL)	55	57	56
Natural gas (MMCF)	476	528	565
Latin America
Oil (MBBL) – Colombia	29	27	28
Natural gas (MMCF) – Bolivia	11	12	13
Middle East/North Africa
Oil (MBBL)
Dolphin	7	6	8
Oman	69	68	66
Qatar	69	67	71
Other	27	38	40
Total	172	179	185
NGLs (MBBL)
Dolphin	7	7	8
Other	—	—	1
Total	7	7	9
Natural gas (MMCF)	422	434	452
Total Sales excluding Hugoton	592	590	598
Hugoton	6	18	19
Total Sales Volumes (MBOE) (a)	598	608	617
(See footnotes following the Average Realized Prices table)

	2014		2013		2012
Average Realized Prices
Oil Prices ($ per bbl)
United States	$	84.73	$	92.48	$	88.25
Latin America	$	88.00	$	103.21	$	98.35
Middle East/North Africa	$	96.34	$	104.48	$	108.76
Total worldwide	$	90.13	$	98.81	$	98.90
NGLs Prices ($ per bbl)
United States	$	37.79	$	38.65	$	44.06
Middle East/North Africa	$	30.98	$	33.00	$	37.74
Total worldwide	$	37.01	$	38.00	$	43.21
Gas Prices ($ per Mcf)
United States	$	3.97	$	3.22	$	2.48
Latin America	$	8.94	$	11.17	$	11.85
Total worldwide (a)	$	2.55	$	2.23	$	1.85

(a) 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.

Oil and gas segment earnings in 2014 included pre-tax charges of $5.3 billion related to the impairment of domestic and international assets and the gain from the sale of Hugoton assets and earnings in 2013 included pre-tax charges of $0.6 billion for the impairment of domestic non-producing acreage. In 2012, oil and gas segment earnings included pre-tax charges of $1.7 billion for the impairment of domestic gas assets and related items.

Domestic oil and gas segment earnings, excluding impairment and other charges in both years, were $1.9 billion in 2014 compared to $2.5 billion in 2013. The decrease in domestic earnings reflected lower crude oil and NGLs prices, higher operating costs from increased workover and maintenance activities, and higher DD&A expenses, partially offset by higher crude oil production volumes and improved realized prices for gas. International oil and gas segment earnings, excluding impairments, were $4.0 billion in 2014 and $4.6 billion in 2013. International earnings reflected lower realized crude oil prices and sales volumes, partially offset by lower operating expenses and DD&A.

Average production costs for 2014, excluding taxes other than on income, were $13.50 per BOE, compared to $12.56 per BOE for 2013. The increase in average costs reflects increased domestic activity in downhole maintenance and higher costs for purchased injectants.

Average daily oil and gas production volumes, excluding Hugoton production, were flat at 591,000 BOE in 2014 and 2013. Average domestic daily production increased by 10,000 BOE to 312,000 BOE in 2014. During this same time period, domestic daily oil production increased by over 6 percent or 11,000 barrels per day to 181,000 barrels, mainly coming from Permian Resources. International average daily production volumes decreased to 279,000 BOE in 2014 from 289,000 BOE in 2013. The decrease was primarily due to lower cost recovery barrels in Iraq and insurgent activities in Colombia, Libya and Yemen. Total company average daily sales volumes, excluding Hugoton, were 592,000 BOE in 2014 and 590,000 BOE in 2013.

Domestic oil and gas segment earnings, excluding impairments in both years, were $2.5 billion in 2013 compared to $2.2 billion in 2012. The increase in domestic earnings reflected higher crude oil and gas prices, higher crude oil volumes and lower operating costs, partially offset by higher DD&A expense. International segment earnings were $4.6 billion in 2013 and $5.5 billion in 2012. The decrease in international earnings reflected lower crude oil prices and volumes as well as higher operating costs and DD&A rates in the Middle East/North Africa.

Average daily oil and gas production volumes, excluding Hugoton, were 591,000 BOE for 2013, compared to 599,000 BOE for 2012. Occidental's 2013 average daily domestic oil and NGLs production increased by 8,000 BOE or 5 percent and 1,000 BOE, respectively, as compared to 2012 while gas production decreased by 30 MMcf or 6 percent as Occidental focused its development program on oil production. International average daily production volumes decreased to 289,000 BOE in 2013 compared to 301,000 BOE in 2012, primarily from lower cost recovery barrels from Dolphin and Oman and higher levels of insurgent activities in Libya. Average daily sales volumes, excluding Hugoton, were 590,000 BOE in 2013, compared to 598,000 BOE in 2012.

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Chemical

(in millions)	2014		2013		2012
Segment Sales	$	4,817	$	4,673	$	4,580
Segment Earnings	$	420	$	743	$	720

Chemical segment earnings, excluding asset impairments of $149 million in 2014 and gain on sale of $131 million from the sale of the Carbocloro investment, were $569 million in 2014 compared to $612 million in 2013. The lower earnings in 2014 were primarily a result of lower caustic soda pricing driven by new chlor-alkali capacity in the industry and higher energy and ethylene costs, partially offset by higher PVC margins and improved volumes across most product lines.

Chemical segment earnings were $612 million in 2013, excluding the $131 million gain on sale of Carbocloro investment, compared to $720 million in 2012. The year-over-year change in chemical segment earnings reflected higher energy and ethylene costs and lower chlor-alkali and chlorinated organics pricing driven by continued unfavorable supply and demand fundamentals and reduced export demand.

Midstream, Marketing and Other

(in millions)	2014		2013		2012
Segment Sales	$	1,373	$	1,174	$	1,164
Segment Earnings	$	2,564	$	1,523	$	440

Midstream and marketing segment earnings in 2014, excluding impairments and other items and gains on sales of $2.0 billion in 2014 and $1.0 billion in 2013, were $549 million in 2014, compared to $537 million in 2013. The increase in earnings reflected higher income from the gas processing and power generation businesses, partially offset by lower marketing performance and pipeline income.

Midstream and marketing segment earnings in 2013 were $537 million, excluding the $1.0 billion pre-tax gain from the sale of a portion of an investment in Plains Pipeline and other items, compared to $396 million in 2012. The 2013 results reflected higher earnings in the pipeline and power generation businesses and improved marketing and trading performance. Marketing performance improved by $110 million, mainly as a result of capturing regional crude price differentials by utilizing new pipelines providing access to the United States gulf coast refineries. These improvements were partially offset by lower income in the gas processing business due in part to the plant turnarounds in the Permian Basin operations.

SIGNIFICANT ITEMS AFFECTING EARNINGS

The following table sets forth, for the years ended December 31, 2014, 2013, and 2012 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)	2014			2013			2012
OIL AND GAS
Hugoton sale gain	$	531		$	—		$	—
Asset impairments and related items domestic	(4,766		)	(607		)	(1,690		)
Asset impairments and related items international	(1,066		)	—			—
Total Oil and Gas	$	(5,301	)	$	(607	)	$	(1,690	)
CHEMICAL
Carbocloro sale gain	$	—		$	131		$	—
Asset impairments	(149		)	—			—
Total Chemical	$	(149	)	$	131		$	—
MIDSTREAM AND MARKETING
BridgeTex Pipeline sale gain	$	633		$	—		$	—
Plains Pipeline sale gain	1,351			1,044			—
Asset impairments and related items	31			(58		)	44
Total Midstream and Marketing	$	2,015		$	986		$	44
CORPORATE
Other than temporary loss on available for sale investment	$	(553	)	$	—		$	—
Joslyn impairment	(805		)
Spin-off costs and other related items	(61		)	—			—
Charge for former employees and consultants	—			(55		)	—
Litigation reserves	—			—			(20		)
Tax effect of pre-tax and other adjustments	927			(167		)	612
Discontinued operations, net of tax	760			971			769
Total Corporate	$	268		$	749		$	1,361

TAXES

Deferred tax liabilities, net of deferred tax assets of $1.4 billion, were $2.9 billion at December 31, 2014. The current portion of the deferred tax assets of $110 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)	2014			2013			2012
EARNINGS
Oil and Gas	$	428		$	6,411		$	5,840
Chemical	420			743			720
Midstream and Marketing (a)	2,564			1,523			440
Unallocated Corporate Items	(1,871		)	(531		)	(512		)
Pre-tax income	1,541			8,146			6,488
Income tax expense
Federal and State	(157		)	1,061			235
Foreign	1,842			2,153			2,424
Total income tax expense	1,685			3,214			2,659
Income (loss) from continuing operations(a)	$	(144	)	$	4,932		$	3,829
Worldwide effective tax rate	109		%	40		%	41		%

(a) Represents amounts attributable to income from continuing operations after deducting a non controlling interest amount of $14 million in 2014. The non controlling interest amount has been netted in the midstream and marketing segment earnings.

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Occidental’s 2014 worldwide tax rate was 109 percent, which was higher than 2013 mainly due to an other than temporary loss on Occidental’s available for sale investment in California Resources stock and the oil and gas international asset impairments of $1.1 billion, neither of which had a tax benefit. To a lesser degree, foreign pre-tax income was proportionately higher in 2014, which is generally taxed at a higher rate than domestic pre-tax income. The 2013 worldwide tax rate was lower than 2012 due to proportionately higher domestic pre-tax income in 2013.

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, an additional deferred tax liability of approximately $140 million would be required, assuming utilization of available foreign tax credits.

CONSOLIDATED RESULTS OF OPERATIONS

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

Revenue and Other Income Items

(in millions)	2014		2013		2012
Net sales	$	19,312	$	20,170	$	20,100
Interest, dividends and other income	$	130	$	107	$	80
Gain on sale of assets and equity investments	$	2,505	$	1,175	$	—

The decrease in net sales in 2014, compared to 2013, was mainly due to a significant decline in worldwide oil prices in the fourth quarter of 2014 and to a lesser extent, decline in NGLs prices, partially offset by higher domestic oil volumes and higher domestic natural gas prices.

The increase in net sales in 2013, compared to 2012, was due to improved domestic oil and gas realized prices and higher crude oil volumes, partially offset by lower international liquids volumes and oil prices.

Price and volume changes in the oil and gas segment generally represent about 70 percent of the change in oil and gas segment income which is a substantially larger portion of the overall change in net income than the chemical and midstream and marketing segments.

The 2014 gains on sale included $1.4 billion for the sale of a portion of the investment in Plains Pipeline, $633 million for the sale of BridgeTex Pipeline and $531 million for the sale of Hugoton properties. The 2013 gains on sale included $1.0 billion for the sale of a portion of the investment in Plains Pipeline and $131 million for the sale of the Carbocloro investment.

Expense Items

(in millions)	2014		2013		2012
Cost of sales	$	6,803	$	6,497	$	6,530
Selling, general and administrative and other operating expenses	$	1,503	$	1,544	$	1,366
Depreciation, depletion and amortization	$	4,261	$	4,203	$	3,585
Asset impairments and related items	$	7,379	$	621	$	1,710
Taxes other than on income	$	550	$	564	$	513
Exploration expense	$	150	$	140	$	197
Interest and debt expense, net	$	77	$	132	$	154

Cost of sales increased in 2014, compared to 2013, due to higher energy and feedstock costs in the chemical segment and increased domestic down hole maintenance activities and higher costs for purchased injectants in the oil and gas segment.

Cost of sales decreased in 2013, compared to 2012, due to lower oil and gas operating costs, partially offset by higher energy and feedstock costs in the chemical segment.

Selling, general and administrative and other operating expenses in 2014 were approximately equivalent to 2013.

Selling, general and administrative and other operating expenses increased in 2013 due to higher compensation and employee-related costs, in particular higher equity compensation due to higher stock prices, as well as the charge related to the employment and post-employment benefits for Occidental's former Executive Chairman and termination of certain other employees and consulting arrangements.

DD&A increased in each year from 2012 to 2014, generally due to higher DD&A rates and, to a lesser extent, the changes in volumes in the oil and gas segment.

Asset impairments and related items in 2014 of $7.4 billion included $2.8 billion in the Williston basin, $904 million related to Occidental's gas and NGLs assets, $889 million for other domestic acreage and $1.1 billion primarily related to operations in Bahrain and other international operations. Asset impairments also include charges for Joslyn oil sands of $805 million and an other than temporary loss of $553 million for the available for sale investment in California Resources stock. See Note 15 of the Consolidated Financial Statements.

Asset impairments and related items in 2013 of $621 million were mostly related to the impairment of certain non-producing domestic oil and gas acreage.

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 previously when gas prices were above $6 per Mcf.

Taxes other than on income in 2014 were approximately equivalent to 2013. From 2013 to 2012 taxes other than on income increased primarily due to rising prices.

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Other Items

Income/(expense) (in millions)	2014			2013			2012
Provision for income taxes	$	(1,685	)	$	(3,214	)	$	(2,659	)
Income from equity investments	$	331		$	395		$	363
Discontinued operations, net	$	760		$	971		$	769

Provision for income taxes decreased in 2014, compared to 2013, due to lower pre-tax income, partially offset by certain nondeductible charges which increased the effective rate.

Provision for income taxes increased in 2013, compared to 2012, 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 2013, compared to 2012.

Income from equity investments decreased in 2014, compared to 2013, due to Occidental’s reduced ownership in the Plains Pipeline as portions of the investment were sold in fourth quarters of 2014 and 2013. The increase in equity income in 2013, compared to 2012, reflected higher earnings from Occidental’s equity investments in pipelines.

CONSOLIDATED ANALYSIS OF FINANCIAL POSITION

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

Balance Sheet Components

(in millions)	2014		2013
CURRENT ASSETS
Cash and cash equivalents	$	3,789	$	3,393
Restricted cash	4,019		—
Trade receivables, net	4,206		5,674
Inventories	1,052		1,200
Other current assets	807		1,056
Total current assets	$	13,873	$	11,323
Investments in unconsolidated entities	$	1,171	$	1,459
Available for sale investment	$	394	$	—
Property, plant and equipment, net	$	39,730	$	55,821
Long-term receivables and other assets, net	$	1,091	$	840
CURRENT LIABILITIES
Accounts payable	$	5,229	$	5,520
Accrued liabilities	2,601		2,556
Domestic and foreign income taxes	414		358
Total current liabilities	$	8,244	$	8,434
Long-term debt, net	$	6,838	$	6,939
Deferred credits and other liabilities-income taxes	$	3,015	$	7,197
Deferred credits and other liabilities-other	$	3,203	$	3,501
Stockholders’ equity	$	34,959	$	43,372

Assets

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

The decline in trade receivables, net, was due to lower oil and gas prices at the end of 2014, compared to the end of 2013. The decrease in inventories primarily resulted from lower storage inventories. The decrease in other current assets mainly reflected the spin-off of California Resources. The decrease in investments in unconsolidated entities was

due to the sale of a portion of Occidental's interest in Plains Pipeline. The retained interest in California Resources after the separation is recorded as an available for sale investment. The decrease in PP&E, net, was due to the spin-off of California Resources, DD&A and asset impairments, partially offset by capital expenditures and acquisitions of oil and gas properties.

Liabilities and Stockholders' Equity

The decrease in accounts payable reflected the spin-off of California Resources and lower marketing payables as a result of lower oil and gas prices at the end of 2014, partially offset by an increase in accounts payable associated with increased Permian development activities.

The decrease in deferred credits and other liabilities-income taxes reflected the spin-off of California Resources as a portion of the deferred tax liability was divested. The decrease in deferred credits and other liabilities-other was primarily due to the reduction of asset retirement obligations as a result of the spin-off of California Resources. The decrease in stockholders' equity reflected the distribution of California Resources stock as a one-time stock dividend, the distribution of cash dividends and share repurchases, partially offset by 2014 net income.

LIQUIDITY AND CAPITAL RESOURCES

At December 31, 2014, Occidental had approximately $3.8 billion in cash and cash equivalents and $4 billion in restricted cash. A substantial majority of this cash is held and available for use in the United States, and Occidental believes the cash in foreign jurisdictions can be brought to the United States without paying significant taxes.Income and cash flows are largely dependent on the oil and gas segment's prices, sales volumes and costs. 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.

As a result of the tax-free status of the spin-off of California Resources, Occidental's use of restricted cash is limited to the payment of dividends, repayment of debt or share repurchases. To retain the tax-free status of the spin-off, the restricted cash must be used for one of these purposes within eighteen months from the date of distribution.

In August 2014, Occidental entered into a new five-year, $2.0 billion bank credit facility (2014 Credit Facility) which replaced its previous $2.0 billion bank credit facility (2011 Credit Facility), which was scheduled to expire in October 2016. The 2014 Credit Facility has similar terms to the 2011 Credit Facility and does not contain material adverse change clauses or debt ratings triggers that could restrict Occidental's ability to borrow under this facility. Occidental did not draw down any amounts under the 2014 Credit Facility or the 2011 Credit Facility during 2014 and no amounts were outstanding as of December 31, 2014.

As of December 31, 2014, 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.

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

Cash Flow Analysis

Cash provided by operating activities
(in millions)	2014		2013		2012
Operating cash flow from continuing operations	$	8,871	$	10,229	$	9,050
Operating cash flow from discontinued operations, net of taxes	2,197		2,549		2,249
Net cash provided by operating activities	$	11,068	$	12,778	$	11,299

Cash provided by operating activities from continuing operations decreased $1.3 billion in 2014 to $8.9 billion, compared to $10.2 billion in 2013. Operating cash flows were negatively impacted by lower oil prices in the second half of 2014, which on a year-over-year basis declined 8-percent domestically and 9-percent worldwide, and higher domestic operating expenses for increased workover activity and higher prices for purchased injectants. Also in 2014, Occidental paid higher income taxes, in part related to the fourth quarter 2013 sale of a portion of the investment in Plains Pipeline and the first half of 2014 sale of Hugoton assets, while 2013 included the collection of a tax receivable. Working capital changes in receivables reflected higher collections in the first half of 2014.

Cash provided by operating activities from continuing operations in 2013 increased $1.1 billion to $10.2 billion, from $9.1 billion in 2012. The increase in operating cash flows was mainly from domestic operations driven by lower operating costs, which reflected our cost savings initiatives, higher realized prices for oil and gas of nearly 5 percent and 30 percent, respectively, and higher oil production volumes. Also, cash flows from our foreign operations were negatively impacted by lower sales volumes in the Middle East/North Africa. In addition, cash flows were impacted favorably due to the collection of a federal tax receivable which was booked in 2012 and other working capital changes.

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 flows than changes in oil and gas product prices, sales volumes and operating costs.

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

Occidental booked significant non-cash adjustments to income as a result of lower product prices and management’s strategic review. Asset impairments and related items were $7.4 billion, $0.6 billion and $1.7 billion for 2014, 2013 and 2012, respectively. The 2014 impairments are the result of a thorough portfolio review which resulted in the reduction of carrying values for projects which have sub-par returns in the current price environment. The 2013 impairment was mostly related to non-producing domestic oil and gas acreage and the 2012

impairment was mainly for Midcontinent gas properties that were acquired when gas prices were over $6 Mcf.

Occidental recorded gains from the sales of assets and equity investments of $2.5 billion in 2014 and $1.2 billion in 2013. Cash proceeds related to these gains are reported as investing activities.

Cash used by investing activities
(in millions)	2014			2013			2012
Capital expenditures
Oil and Gas	$	(6,533	)	$	(5,409	)	$	(6,025	)
Chemical	(314		)	(424		)	(357		)
Midstream and Marketing	(1,983		)	(1,360		)	(1,401		)
Corporate	(100		)	(164		)	(91		)
Total	(8,930		)	(7,357		)	(7,874		)
Other investing activities, net	2,686			1,040			(1,989		)
Net cash used by investing activities – continuing operations	(6,244		)	(6,317		)	(9,863		)
Investing cash flow from discontinued operations	(2,226		)	(1,727		)	(2,779		)
Net cash used by investing activities	$	(8,470	)	$	(8,044	)	$	(12,642	)

Compared to $7.2 billion in 2013, Occidental's net capital expenditures for 2014 were $8.7 billion after netting of partner contributions for the BridgeTex pipeline, which is included in financing activities, and the Chemical joint venture. The increase in capital expenditures of $1.5 billion from 2013 to 2014 was due to increased development activity in the domestic oil and gas operations, primarily Permian Resources. The increase in the midstream and marketing capital expenditures was due to higher spending for the Al Hosn gas project and BridgeTex pipeline.

Occidental’s 2015 net capital spending is expected to be $5.8 billion, mainly allocated to Permian Resources and certain Middle East projects. Occidental has minimized development activities in the Williston Basin, domestic gas properties and Bahrain, as these have sub-par returns in the current product price environment. Oil and gas capital spending is expected to be approximately $4.5 billion in 2015.

Compared to $7.8 billion in 2012, Occidental's net capital expenditures for 2013 were $7.2 billion, net of partner contributions. The decrease in capital expenditures from 2012 to 2013 was mainly due to the $0.6 billion decrease in oil and gas expenditures, a majority of which was in domestic properties. This reduction reflected cost savings from Occidental's efficiency initiatives. The increase for the chemical segment was due to the continued construction of the Tennessee chlor-alkali facility. The decrease in the midstream and marketing capital expenditures was due to lower spending for the Al Hosn gas project, partially offset by increased spending for BridgeTex pipeline.

Cash flows from other investing activities, net, increased to $2.7 billion in 2014 from $1.0 billion in 2013. The 2014 other investing activities, net, included proceeds of $1.3 billion for the sale of the Hugoton Field operations, $1.1 billion for the sale of the BridgeTex Pipeline and $1.7 billion for the sale of a portion of Occidental’s investment in Plains Pipeline, which was partially offset by $1.7 billion of acquisitions, mainly in the Permian Basin. The 2013 other

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investing activities, net included proceeds of $1.4 billion for the sale of a portion of the investment in Plains Pipeline and $0.3 billion for the sale of Chemical’s investment in Carbocloro, which was partially offset by acquisitions of approximately $0.6 billion.

The 2012 other investing activities, net included $2.0 billion in payments for the acquisition of businesses and assets.

Commitments at December 31, 2014 for major fixed and determinable capital expenditures were approximately $1.4 billion, which will be due in 2015 and beyond.  Occidental expects to fund its commitments and capital expenditures with cash from operations.

Cash used by financing activities
(in millions)	2014			2013			2012
Financing cash flow from continuing operations	$	(2,326	)	$	(2,933	)	$	(846	)
Financing cash flow from discontinued operations	124			—			—
Net cash used by financing activities	$	(2,202	)	$	(2,933	)	$	(846	)

Cash used for financing activities in 2014 included special cash distributions received prior to the separation of California Resources of $6.1 billion, of which $4.95 billion was restricted cash. Approximately $0.9 billion of the restricted cash was used for share repurchases and the fourth quarter dividend payment, resulting in a $4.0 billion restricted cash balance as of December 31, 2014. The 2014 net cash used by financing activities included $2.5 billion for purchases of treasury stock and $2.2 billion for dividend payments, which were partially offset by $0.4 billion for contributions received from a noncontrolling interest. A dividend payment was accelerated in 2012 which resulted in three dividend payments in 2013, whereas there were four cash dividend payments in 2014.

The 2013 net cash used by financing activities included $0.7 billion used to retire debt and $0.2 billion of contributions received from a noncontrolling interest. Common stock dividends paid decreased by $0.6 billion to $1.6 billion in 2013, due to the accelerated payment in 2012 of that year's fourth quarter dividend. In addition, purchases of treasury stock increased from $0.6 billion in 2012 to over $0.9 billion in 2013. Higher 2013 net cash use compared to 2012 also reflected the net proceeds in 2012 of approximately $1.7 billion from the issuance of senior unsecured notes that year.

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 its portion of equity method 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, 2014, Occidental’s

guarantees were not material and a substantial majority consisted of limited recourse guarantees on approximately $336 million of Dolphin’s debt. The fair value of the guarantees was immaterial.

Occidental has guaranteed certain obligations of its subsidiaries for various letters of credit, indemnities and commitments. Marketing guarantees provided to third parties for California Resources total approximately $161 million as of December 31, 2014. The fair value of the marketing guarantees and other obligations of California Resources guaranteed by Occidental were immaterial.

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

Leases

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

CONTRACTUAL OBLIGATIONS

The table below summarizes and cross-references Occidental’s contractual obligations. This summary indicates on- and off-balance-sheet obligations as of December 31, 2014.

Contractual Obligations (in millions)			Payments Due by Year
	Total		2015		2016 and 2017		2018 and 2019		2020 and thereafter
On-Balance Sheet
Long-term debt (Note 5) (a)	$	6,857	$	—	$	2,700	$	616	$	3,541
Other long-term liabilities (b)	1,808		125		391		282		1,010
Off-Balance Sheet
Operating leases (Note 6)	1,386		192		330		272		592
Purchase obligations (c)	10,109		3,280		2,684		1,244		2,901
Total	$	20,160	$	3,597	$	6,105	$	2,414	$	8,044

(a) Excludes unamortized debt discount and interest on the debt.  As of December 31, 2014, interest on long-term debt totaling $1.2 billion is payable in the following years (in millions): 2015 - $215, 2016 and 2017 - $328, 2018 and 2019 - $271, 2020 and thereafter - $354.

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

(c) Amounts include payments which will become due under long-term agreements to purchase goods and services used in the normal course of business to secure terminal and pipeline capacity, drilling rigs and services, CO_2, electrical power, steam and certain chemical raw materials. Amounts exclude certain product purchase obligations related to marketing and trading activities for which there are no minimum purchase requirements or the amounts are not fixed or determinable.  Long-term purchase contracts are discounted at a 3.14 percent discount rate.

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Delivery Commitments

Occidental has made commitments to certain refineries and other buyers to deliver oil, gas and NGLs. The total amount contracted to be delivered, a substantial majority of which is in the United States, is approximately 430 million barrels of oil through 2025, 37 billion cubic feet of gas through 2016 and 24 million barrels of NGLs through 2016. 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 has the ability to secure additional volumes in case of a shortfall. None of the commitments in any given year is expected to have a material impact on Occidental's financial statements.

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 or disposed assets with respect to which a third party or Occidental retains liability or indemnifies the other party for conditions that existed prior to the transaction.

Occidental has entered into a written settlement agreement with the State of New Jersey (the State) to resolve claims asserted by the State against Occidental arising from Occidental’s acquisition of Diamond Shamrock Chemicals Company (DSCC) and historic operations of DSCC’s Lister Avenue Plant. In December 2014, the settlement was approved by the court. Under the settlement agreement (State Settlement) Occidental will pay the State $190 million and, under certain circumstances, perform or fund future work on behalf of the State along a portion of the Passaic River. When Occidental acquired the stock of DSCC in 1986, Maxus Energy Corporation, a subsidiary of YPF S.A. (Maxus), retained liability for the Lister Avenue Plant, which is part of the Diamond Alkali Superfund Site, as well as other sites. Maxus is also obligated to indemnify Occidental for the State Settlement. Occidental is pursuing Maxus to recover the settlement costs. The State Settlement does not cover any potential Occidental share of costs associated with the EPA’s proposed clean-up plan of the Passaic River announced in April 2014. Maxus is also responsible for federal clean-up or other costs associated with the Lister Avenue Plant and the Diamond Alkali Superfund Site.

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, 2014 and 2013 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.

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, 2014, 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.

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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, 2014, Occidental participated in or monitored remedial activities or proceedings at 145 sites, excluding seven sites transferred to California Resources prior to December 31, 2014. The following table presents Occidental’s environmental remediation reserves as of December 31, 2014, 2013 and 2012, grouped as environmental remediation sites listed or proposed for listing by the U.S. Environmental Protection Agency on the CERCLA National Priorities List (NPL sites) and three categories of non-NPL sites — third-party sites, Occidental-operated sites and closed or non-operated Occidental sites.

($ amounts  in millions)	2014			2013			2012
	# of Sites	Reserve Balance		# of Sites	Reserve Balance		# of Sites	Reserve Balance
NPL sites	30	$	23	31	$	25	35	$	54
Third-party sites	67	101		74	83		75	84
Occidental-operated sites	17	107		20	118		22	123
Closed or non-operated Occidental sites	31	103		32	104		29	83
Total	145	$	334	157	$	330	161	$	344

As of December 31, 2014, Occidental’s environmental reserves exceeded $10 million each at 11 of the 145 sites described above, and 98 of the sites had reserves from $0 to $1 million each.

As of December 31, 2014, two sites — a landfill in western New York owned by Occidental and a former refinery in Louisiana — accounted for 62 percent of its reserves associated with NPL sites. In connection with a 1986 acquisition, Maxus Energy Corporation has retained the liability and is indemnifying Occidental for 14 of the remaining NPL sites.

As of December 31, 2014, Maxus has also retained the liability and is indemnifying Occidental for 8 of the 67 third-party sites. Four of the remaining 59 third-party sites — a former copper mining and smelting operation in Tennessee, a containment and removal project in Tennessee, a former chemical plant in Ohio and an active refinery in Louisiana where Occidental reimburses the current owner for certain

remediation activities — accounted for 56 percent of Occidental’s reserves associated with these sites.

Four sites — chemical plants in Kansas, Louisiana and New York and a group of oil and gas properties in the southwestern United States — accounted for 62 percent of the reserves associated with the Occidental-operated sites.

Four other sites — a landfill in western New York, former chemical plants in Tennessee and Delaware and a closed coal mine in Pennsylvania — accounted for 63 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)	2014			2013			2012
Balance — Beginning of Year	$	330		$	344		$	360
Remediation expenses and interest accretion	79			60			56
Spin-off of California Resources	(7		)	—			—
Payments	(68		)	(74		)	(72		)
Balance — End of Year	$	334		$	330		$	344

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 three to 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 $380 million. See "Critical Accounting Policies and Estimates — Environmental Liabilities and Expenditures" for additional information.

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)	2014		2013		2012
Operating Expenses
Oil and Gas	$	103	$	100	$	116
Chemical	80		75		70
Midstream and Marketing	11		13		13
	$	194	$	188	$	199
Capital Expenditures
Oil and Gas	$	143	$	67	$	79
Chemical	35		14		18
Midstream and Marketing	11		5		8
	$	189	$	86	$	105
Remediation Expenses
Corporate	$	79	$	60	$	56

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

Occidental presently estimates capital expenditures for environmental compliance of approximately $160 million for 2015.

FOREIGN INVESTMENTS

Many of Occidental’s assets are located outside North America. At December 31, 2014, the carrying value of Occidental’s assets in countries outside North America aggregated approximately $15 billion, or approximately 27 percent of Occidental’s total assets at that date. Of such assets, approximately $13 billion are located in Middle East/North Africa and approximately $2 billion are located in Latin America. For the year ended December 31, 2014, net sales outside North America totaled $7.3 billion, or approximately 38 percent of total net sales.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The process of preparing financial statements in accordance with generally accepted accounting principles (GAAP) 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.

Oil and Gas Properties

The carrying value of Occidental’s 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 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, the costs of injectants used in production and geological, geophysical and seismic costs as incurred.

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 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 product prices rise and increases when prices decline. Overall, Occidental’s net economic benefit from these contracts is greater at higher product 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 2014, revisions of previous estimates caused a net 58 million BOE decrease in proved reserves, which amounted to approximately 2 percent of Occidental's total reserves as of December 31, 2014.

Additionally, Occidental performs impairment tests with respect to its proved properties whenever events or circumstances indicate that the carrying value of property may not be recoverable. If there is an indication the carrying amount of the asset may not be recovered due to declines in current and forward prices, significant changes in reserve estimates, changes in management's plans, or other significant events, management will evaluate the property for impairment. Under the successful efforts method, if the sum of the undiscounted cash flows is less than the carrying value of the proved property, the carrying value is reduced to estimated fair value and reported as an impairment

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charge in the period. Individual proved properties are grouped for impairment purposes at the lowest level for which there are identifiable cash flows, which is generally on a field by field basis. The fair value of impaired assets is typically determined based on the present value of expected future cash flows using discount rates believed to be consistent with those used by market participants. The impairment test incorporates a number of assumptions involving expectations of future cash flows which can change significantly over time. These assumptions include estimates of future product prices, contractual prices, estimates of risk-adjusted proved oil and gas reserves and estimates of future operating and development costs.

The most significant ongoing financial statement effect from a change in Occidental's oil and gas reserves or impairment of its proved properties 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 $0.70 per barrel, which would increase or decrease pre-tax income by approximately $155 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, 2014, the net capitalized costs attributable to unproved properties were $2.0 billion. The unproved amounts are not subject to DD&A until they are classified as proved properties. Capitalized costs attributable to the properties become subject to DD&A when proved reserves are assigned to the property. If the exploration efforts are unsuccessful, or management decides not to pursue development of these properties as a result of lower commodity prices, higher development and operating costs, contractual conditions or other factors, 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.

During its annual capital planning process in the fourth quarter of 2014, management determined that it would not pursue development of certain of its non-producing domestic oil and gas acreage based on product prices, availability of transportation capacity to market the products and regulatory and environmental considerations. As a result, Occidental recorded pre-tax impairment charges of $1.4 billion for the acreage. In addition, during the second quarter of 2014, Occidental recorded a pre-tax impairment charge of $471 million for domestic non-producing acreage.

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 2015 is expected to be approximately $310 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 $50 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 lack of correlation between the hedged item and the hedging instrument due to location, quality, grade or changes in the expected quantity of the

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hedged item. 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, 2014, 2013 and 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.

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 the assets or liabilities; Level 2 – using observable inputs other than quoted prices for the assets or liabilities; and Level 3 – using unobservable inputs.  Transfers between levels, if any, are recognized at the end of each reporting period.

Fair Values - Recurring

Occidental primarily applies the market approach for recurring fair value measurements, maximizes its use of observable inputs and minimizes its use of unobservable inputs. Occidental utilizes the mid-point 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 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 classified as Level 2 and 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.

Ø Occidental values 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 generally unobservable in the marketplace or are observable but have been adjusted based upon various assumptions 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 and related charges and expenses 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, 2014, 2013 and 2012, 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

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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 may occur.

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 $33 million. If the reserve balance were increased by 10 percent, Occidental would record an additional remediation expense of $33 million.

Other Loss Contingencies

Occidental is involved, in the normal course of business, in lawsuits, claims and other legal proceedings and audits. Occidental accrues reserves for these matters when it is probable that a liability has been incurred and the liability 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 Contingencies" for additional information.

SIGNIFICANT ACCOUNTING AND DISCLOSURE CHANGES

Listed below are significant recently adopted accounting and disclosure changes.

In January 2015, the Financial Accounting Standards Board (FASB) issued rules which eliminate from GAAP the concept of extraordinary item. The presentation and disclosure guidance for items that are unusual in nature or occur infrequently will be retained and will be expanded to include items that are both unusual in nature and infrequently occurring. The rules are not expected to have an impact on Occidental’s financial statements upon adoption.

In June 2014, the FASB issued rules affecting entities that grant their employees share-based payment awards in which the terms of the awards provide that a performance target can be achieved after the requisite service period. The new rules require that a performance target that affects vesting and that could be achieved after the requisite service period be treated as a performance condition. Entities may apply the update either: (a) prospectively to all awards granted or modified after the effective date; or (b) retrospectively to all awards with performance targets that are outstanding as of the beginning of the earliest annual period presented in the financial statements and to all new or modified awards thereafter. These rules are effective for annual periods beginning on or after December 15, 2015. The rules are not expected to have a material impact on Occidental's financial statements upon adoption but will require assessment on an ongoing basis.

In May 2014, the FASB issued rules relating to revenue recognition. Under the new rules, an entity will recognize revenue when it transfers promised goods or services to customers in an amount that reflects what it expects to receive in exchange for the goods or services. The rules also require more detailed disclosures related to the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. These rules are effective for the Company for interim and annual periods beginning after December 15, 2016. The rules are not expected to have a material impact on Occidental's financial statements upon adoption.

In April 2014, the FASB issued rules changing the requirements for reporting discontinued operations so that only the disposals of components of an entity that represent a strategic shift that has (or will have) a major effect on an entity's operations and financial results will be reported as discontinued operations in the financial statements. These rules are effective for annual periods beginning on or after December 15, 2014. The rules are not expected to have a material impact on Occidental's financial statements upon adoption.

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In July 2013, the FASB issued rules requiring net, rather than gross, presentation of a deferred tax asset for a net operating loss or other tax credit and any related liability for unrecognized tax benefits. The rules became effective on January 1, 2014, and did not have a material impact on Occidental's financial statements.

SAFE HARBOR DISCUSSION REGARDING OUTLOOK AND OTHER FORWARD-LOOKING DATA

Portions of this report, including Items 1 and 2 "Business and Properties," Item 3, "Legal Proceedings," Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations," and Item 7A, "Quantitative and Qualitative Disclosures About Market Risk," contain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 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 the factors discussed in Item 1A "Risk Factors" and elsewhere.

ITEM 7A

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

General

Occidental’s results are sensitive to fluctuations in oil, NGLs and natural gas prices. Price changes at current global prices and levels of production affect Occidental’s pre-tax annual income by approximately $126 million for a $1 per barrel change in oil prices and $27 million for a $1 per barrel change in NGLs 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 $50 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 prices also will change. The marketing and trading results are 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 IHS Chemical, December 2014 average contract prices were: chlorine—$233 per ton; caustic soda—$590 per ton; and PVC—$0.67 per lb.

Occidental uses derivative instruments, including a combination of short-term futures, forwards, options and swaps, to obtain the average prices for the relevant production month 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.

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 a Risk Management group which manages risk by providing an independent and separate evaluation and check. Members of the Risk Management group report to the Corporate Vice President and Treasurer.  The President and Chief Executive Officer, and Executive Vice President of Operations 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 carries derivative contracts it enters into in connection with its marketing and trading activities at fair value. Fair values for these contracts are derived principally from Level 1 and Level 2 sources.

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)	2015			2016 and 2017			2018 and 2019			2020 and thereafter			Total
Prices actively quoted	$	(37	)	$	(1	)	$	(35	)	$	(26	)	$	(99	)
Prices provided by other external sources	(20		)	(38		)	—			—			(58		)
Total	$	(57	)	$	(39	)	$	(35	)	$	(26	)	$	(157	)

Note: Includes cash-flow hedges further discussed below.

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Cash-Flow Hedges

Occidental’s marketing and trading operations, from time to time, store natural gas purchased from third parties at Occidental’s North American leased storage facilities. Derivative instruments used to fix margins on the future sales of the stored volumes ended March 31, 2014. As of December 31, 2014, Occidental did not have any cash-flow hedges on stored volumes of natural gas. At December 31, 2013, Occidental had approximately 11 billion cubic feet of natural gas held in storage, and had cash-flow hedges for the forecast sale, to be settled by physical delivery, of approximately 13 billion cubic feet of stored natural gas.

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 its operations.  

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, 2014, 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)
2015	$	—		$	—		$	—
2016	1,450			—			1,450
2017	1,250			—			1,250
2018	500			—			500
2019	116			—			116
Thereafter	3,473			68			3,541
Total	$	6,789		$	68		$	6,857
Weighted-average interest rate	3.17		%	0.04		%	3.14		%
Fair Value	$	6,976		$	68		$	7,044

(a) Excludes unamortized debt discounts of $19 million.

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. Credit exposure for each customer is monitored for outstanding balances, current activity, and forward mark-to-market exposure.

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

Certain of Occidental's OTC derivative instruments contain credit-risk-contingent features, primarily tied to credit ratings for Occidental or its counterparties, which may affect the amount of collateral that each would need to post. As of December 31, 2014 and 2013, Occidental had a net liability of $4 million and $8 million, respectively, which are net of collateral posted of $3 million and $23 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, 2014 and 2013.

As of December 31, 2014, the substantial majority of the credit exposures was with investment grade counterparties. Occidental believes its exposure to credit-related losses at December 31, 2014 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, 2014, 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.

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ITEM 8    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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, 2014 and 2013, 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, 2014. In connection with our audits of the consolidated financial statements, we also have audited financial statement schedule II - valuation and qualifying accounts. 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, 2014 and 2013, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2014, 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, 2014, based on criteria established in Internal Control - Integrated Framework issued in 2013 by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 23, 2015 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

Houston, Texas

February 23, 2015

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, 2014, based on criteria established in Internal Control - Integrated Framework issued in 2013 by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Occidental Petroleum Corporation’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, 2014, based on criteria established in Internal Control - Integrated Framework issued in 2013 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, 2014 and 2013, 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, 2014, and our report dated February 23, 2015 expressed an unqualified opinion on those consolidated financial statements.

Houston, Texas

February 23, 2015

39

Consolidated Balance Sheets	Occidental Petroleum Corporation and Subsidiaries
(in millions)

Assets at December 31,	2014			2013
CURRENT ASSETS
Cash and cash equivalents	$	3,789		$	3,393
Restricted cash	4,019			—
Trade receivables, net of reserves of $17 in 2014 and $17 in 2013	4,206			5,674
Inventories	1,052			1,200
Other current assets	807			1,056
Total current assets	13,873			11,323
INVESTMENTS
Investment in unconsolidated entities	1,171			1,459
Available for sale investment	394			—
Total investments	1,565			1,459
PROPERTY, PLANT AND EQUIPMENT
Oil and gas segment	59,061			72,367
Chemical segment	6,574			6,446
Midstream, marketing and other segment	8,304			8,684
Corporate	576			1,555
	74,515			89,052
Accumulated depreciation, depletion and amortization	(34,785		)	(33,231		)
	39,730			55,821
LONG-TERM RECEIVABLES AND OTHER ASSETS, NET	1,091			840
TOTAL ASSETS	$	56,259		$	69,443

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,	2014			2013
CURRENT LIABILITIES
Accounts payable	$	5,229		$	5,520
Accrued liabilities	2,601			2,556
Domestic and foreign income taxes	414			358
Total current liabilities	8,244			8,434
LONG-TERM DEBT, NET	6,838			6,939
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred domestic and foreign income taxes	3,015			7,197
Other	3,203			3,501
	6,218			10,698
CONTINGENT LIABILITIES AND COMMITMENTS
STOCKHOLDERS' EQUITY
Common stock, $0.20 per share par value, authorized shares: 1.1 billion, outstanding shares: 2014 — 890,557,537 and 2013 — 889,919,058	178			178
Treasury stock:  2014 — 119,951,199 shares and 2013 — 93,928,179 shares	(8,528		)	(6,095		)
Additional paid-in capital	7,599			7,515
Retained earnings	36,067			41,831
Accumulated other comprehensive loss	(357		)	(303		)
Total equity attributable to common stock	34,959			43,126
Noncontrolling interest	—			246
Total equity	34,959			43,372
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	56,259		$	69,443

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,	2014			2013			2012
REVENUES AND OTHER INCOME
Net sales	$	19,312		$	20,170		$	20,100
Interest, dividends and other income	130			107			80
Gain on sale of assets and equity investments	2,505			1,175			—
	21,947			21,452			20,180
COSTS AND OTHER DEDUCTIONS
Cost of sales (excludes depreciation, depletion and amortization of $4,257 in 2014, $4,197 in 2013 and $3,578 in 2012)	6,803			6,497			6,530
Selling, general and administrative and other operating expenses	1,503			1,544			1,366
Depreciation, depletion and amortization	4,261			4,203			3,585
Asset impairments and related items	7,379			621			1,710
Taxes other than on income	550			564			513
Exploration expense	150			140			197
Interest and debt expense, net	77			132			154
	20,723			13,701			14,055
INCOME BEFORE INCOME TAXES AND OTHER ITEMS	1,224			7,751			6,125
Provision for domestic and foreign income taxes	(1,685		)	(3,214		)	(2,659		)
Income from equity investments	331			395			363
(LOSS) / INCOME FROM CONTINUING OPERATIONS	(130		)	4,932			3,829
Discontinued operations, net	760			971			769
NET INCOME	$	630		$	5,903		$	4,598
Less: Net Income attributable to Non Controlling Interests	(14		)	—			—
NET INCOME ATTRIBUTABLE TO COMMON STOCK	$	616		$	5,903		$	4,598
BASIC EARNINGS PER COMMON SHARE
(Loss)/Income from continuing operations	$	(0.18	)	$	6.12		$	4.72
Discontinued operations, net	0.97			1.21			0.95
BASIC EARNINGS PER COMMON SHARE	$	0.79		$	7.33		$	5.67
DILUTED EARNINGS PER COMMON SHARE
(Loss)/Income from continuing operations	$	(0.18	)	$	6.12		$	4.72
Discontinued operations, net	0.97			1.20			0.95
DILUTED EARNINGS PER COMMON SHARE	$	0.79		$	7.32		$	5.67
DIVIDENDS PER COMMON SHARE	$	2.88		$	2.56		$	2.16
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,	2014			2013			2012
Net income attributable to common stock	$	616		$	5,903		$	4,598
Other comprehensive income (loss) items:
Foreign currency translation (losses) gains	(2		)	2			(25		)
Realized foreign currency translation losses	—			28			—
Unrealized (losses) gains on derivatives (a)	(5		)	(3		)	16
Pension and postretirement (losses) gains (b)	(77		)	176			14
Distribution of California Resources to shareholders (c)	22			—			—
Reclassification to income of realized losses (gains) on derivatives (d)	8			(4		)	(24		)
Other comprehensive (loss) income, net of tax (e)	(54		)	199			(19		)
Comprehensive income	$	562		$	6,102		$	4,579

(a) Net of tax of $3, $2 and $(9) in 2014, 2013 and 2012, respectively.

(b) Net of tax of $44, $(101) and $(8) in 2014, 2013 and 2012, respectively. See Note 13, Retirement and Postretirement Benefit Plans, for additional information.

(c) Net of tax of $(14) in 2014.

(d) Net of tax of $(5), $2 and $14 in 2014, 2013 and 2012, respectively.

(e) There were no other comprehensive income (loss) items related to noncontrolling interests in 2014, 2013 and 2012.

43

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, 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			(a)	32
Purchases of treasury stock	—		(589		)	—		—			—			—				(589		)
Balance, December 31, 2012	$	178	$	(5,091	)	$	7,441	$	37,990		$	(502	)	$	32			$	40,048
Net income	—		—			—		5,903			—			—				5,903
Other comprehensive income, net of tax	—		—			—		—			199			—				199
Dividends on common stock	—		—			—		(2,062		)	—			—				(2,062		)
Issuance of common stock and other, net	—		—			74		—			—			—				74
Noncontrolling interest contributions	—		—			—		—			—			214			(a)	214
Purchases of treasury stock	—		(1,004		)	—		—			—			—				(1,004		)
Balance, December 31, 2013	$	178	$	(6,095	)	$	7,515	$	41,831		$	(303	)	$	246			$	43,372
Net income	—		—			—		616			—			—				616
Other comprehensive income, net of tax	—		—			—		—			(76		)	—				(76		)
Dividends on common stock	—		—			—		(2,252		)	—			—				(2,252		)
Issuance of common stock and other, net	—		—			84		—			—			—				84
Distribution of California Resources stock to shareholders	—		—			—		(4,128		)	22			—				(4,106		)
Noncontrolling interest distributions, net	—		—			—		—			—			(246		)	(a)	(246		)
Purchases of treasury stock	—		(2,433		)	—		—			—			—				(2,433		)
Balance, December 31, 2014	$	178	$	(8,528	)	$	7,599	$	36,067		$	(357	)	$	—			$	34,959

(a) Reflects contributions (disposition) from the noncontrolling interest in BridgeTex Pipeline which was sold in the fourth quarter 2014.

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

44

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

For the years ended December 31,	2014			2013			2012
CASH FLOW FROM OPERATING ACTIVITIES
Net income	$	630		$	5,903		$	4,598
Adjustments to reconcile net income to net cash provided by operating activities:
Discontinued operations, net	(760		)	(971		)	(769		)
Depreciation, depletion and amortization of assets	4,261			4,203			3,585
Deferred income tax provision	(1,178		)	914			580
Other noncash charges to income	115			271			167
Asset impairments and related items	7,379			621			1,710
Gain on sale of equity investments	(2,505		)	(1,175		)	—
Undistributed earnings from equity investments	38			(3		)	(30		)
Dry hole expenses	99			70			151
Changes in operating assets and liabilities:
Decrease (increase) in receivables	1,413			(747		)	452
(Increase) decrease in inventories	(112		)	79			(242		)
Decrease in other current assets	89			58			176
(Decrease) increase in accounts payable and accrued liabilities	(544		)	255			(959		)
(Decrease) increase in current domestic and foreign income taxes	(54		)	369			1
Other operating, net	—			382			(370		)
Operating cash flow from continuing operations	8,871			10,229			9,050
Operating cash flow from discontinued operations, net of taxes	2,197			2,549			2,249
Net cash provided by operating activities	11,068			12,778			11,299
CASH FLOW FROM INVESTING ACTIVITIES
Capital expenditures	(8,930		)	(7,357		)	(7,874		)
Change in capital accrual	542			149			13
Payments for purchases of assets and businesses	(1,687		)	(606		)	(2,084		)
Sales of equity investments and assets, net	4,177			1,619			4
Other, net	(346		)	(122		)	78
Investing cash flow from continuing operations	(6,244		)	(6,317		)	(9,863		)
Investing cash flow from discontinued operations	(2,226		)	(1,727		)	(2,779		)
Net cash used by investing activities	(8,470		)	(8,044		)	(12,642		)
CASH FLOW FROM FINANCING ACTIVITIES
Change in restricted cash	(4,019		)	—			—
Special cash distributions from California Resources	6,100			—			—
Proceeds from long-term debt	—			—			1,736
Payments of long-term debt	(107		)	(690		)	—
Proceeds from issuance of common stock	33			30			85
Purchases of treasury stock	(2,500		)	(943		)	(583		)
Contributions from noncontrolling interest	375			214			32
Cash dividends paid	(2,210		)	(1,553		)	(2,128		)
Other, net	2			9			12
Financing cash flow from continuing operations	(2,326		)	(2,933		)	(846		)
Financing cash flow from discontinued operations	124			—			—
Net cash used by financing activities	(2,202		)	(2,933		)	(846		)
Increase (decrease) in cash and cash equivalents	396			1,801			(2,189		)
Cash and cash equivalents — beginning of year	3,393			1,592			3,781
Cash and cash equivalents — end of year	$	3,789		$	3,393		$	1,592

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

45

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 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 and 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 power. Additionally, the midstream and marketing segment 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 2014 presentation.

As a result of the spin-off of California Resources Corporation (California Resources) the statements of income and cash flows related to California Resources have been treated as discontinued operations for the years ended December 31, 2014, 2013 and 2012. The assets and liabilities of California Resources were removed from Occidental's consolidated balance sheet as of November 30, 2014. See Note 17 Spin-off of California Resources for additional information.

INVESTMENTS IN UNCONSOLIDATED ENTITIES

Occidental’s percentage interest in the underlying net assets of affiliates as to which it exercises significant influence without having a controlling interest (excluding oil and gas ventures in which Occidental holds an undivided interest) are accounted for under the equity method. Occidental reviews equity-method investments for impairment whenever events or changes in circumstances indicate that an other-than-temporary decline in value may have occurred. The amount of impairment, if any, is based on quoted market prices, when available, or other valuation techniques, including discounted cash flows.

REVENUE RECOGNITION

Revenue is recognized from oil and gas production when title has passed to the customer, which occurs when the product is shipped. In international locations where oil is shipped by tanker, title passes when the tanker is loaded or product is received by the customer, depending on the shipping terms. This process occasionally causes a difference between actual production in a reporting period and sales volumes that have been recognized as revenue. Revenues from the production of oil and gas properties in which Occidental has an interest with other producers are recognized on the basis of Occidental’s net revenue interest.

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 expected outcomes as well as 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

46

actual results may differ from estimates upon settlement. Management believes that these estimates and judgments provide a reasonable basis for the fair presentation of Occidental’s financial statements. Occidental establishes a valuation allowance against net operating losses and other deferred tax assets to the extent it believes the future benefit from these assets will not be realized in the statutory carryforward periods. Realization of deferred tax assets, including any net operating loss carryforwards, is dependent upon Occidental generating sufficient future taxable income and reversal of temporary differences in jurisdictions where such assets originate.

The accompanying consolidated financial statements include assets of approximately $15 billion as of December 31, 2014, and net sales of approximately $7.3 billion for the year ended December 31, 2014, relating to Occidental’s operations in countries outside North America. Occidental operates some of its oil and gas business in countries that have experienced political instability, nationalizations, corruption, 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 $3.4 billion and $2.9 billion at December 31, 2014 and 2013, respectively.

RESTRICTED CASH

Restricted cash is the result of the separation of California Resources. As of December 31, 2014, there was $4.0 billion of cash restricted for the payment of dividends, payment of debt or share repurchases. Restricted cash must be used within 18 months of the date of distribution.

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.

A decline in market value of any available-for-sale securities below cost that is deemed to be other-than-temporary results in an impairment to reduce the carrying amount to fair value. To determine whether an impairment is other‑than‑temporary, Occidental considers all available information relevant to the investment, including past events and current conditions. Evidence considered in this assessment includes the reasons for the impairment, the severity and duration of the impairment, changes in value subsequent to year‑end, and the general market condition in the geographic area or industry the investee operates in.

INVENTORIES

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

For the chemical segment, Occidental's 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 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.

47

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

in millions	2014			2013			2012
Balance — Beginning of Year	$	140		$	124		$	189
Additions to capitalized exploratory well costs pending the determination of proved reserves	462			337			400
Reclassifications to property, plant and equipment based on the determination of proved reserves	(423		)	(271		)	(389		)
Spin-off of California Resources	(17		)	—			—
Capitalized exploratory well costs charged to expense	(21		)	(50		)	(76		)
Balance — End of Year	$	141		$	140		$	124

Occidental expenses annual lease rentals, the costs of injectants used in production and geological, geophysical and seismic costs as incurred.

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 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.

Occidental performs impairment tests with respect to its proved properties whenever events or circumstances indicate that the carrying value of property may not be recoverable. If there is an indication the carrying amount of the asset may not be recovered due to declines in current and forward prices, significant changes in reserve estimates, changes in management's plans, or other significant events, management will evaluate the property for impairment. Under the successful efforts method, if the sum of the undiscounted cash flows is less than the carrying value of the proved property, the carrying value is reduced to estimated fair value and reported as an impairment charge in the period. Individual proved properties are grouped for impairment purposes at the lowest level for which there are identifiable cash flows, which is generally on a field by field basis. The fair value of impaired assets is typically determined based on the present value of expected future cash flows using discount rates believed to be consistent with those used by market participants. The impairment test incorporates a number of assumptions involving expectations of future cash flows which can change significantly over time. These assumptions include estimates of future product prices, contractual prices, estimates of risk-adjusted proved oil and gas reserves and estimates of future operating and development costs. See Note 15 for further discussion of asset impairments.

A portion of the carrying value of Occidental’s oil and gas properties is attributable to unproved properties. At December 31, 2014, the net capitalized costs attributable to unproved properties were $2.0 billion. The unproved amounts are not subject to DD&A until they are classified as proved properties. Capitalized costs attributable to the properties become subject to DD&A when proved reserves are assigned to the property. If the exploration efforts are unsuccessful, or management decides not to pursue development of these properties as a result of lower commodity prices, higher development and operating costs, contractual conditions or other factors, 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.

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.

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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 the assets or liabilities; Level 2 – using observable inputs other than quoted prices for the assets or liabilities; and Level 3 – using unobservable inputs. Transfers between levels, if any, are reported at the end of each reporting period.

Fair Values - Recurring

Occidental primarily applies the market approach for recurring fair value measurements, maximizes its use of observable inputs and minimizes its use of unobservable inputs. Occidental utilizes the mid-point 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 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 classified as Level 2 and 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.

Ø Occidental values 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 generally unobservable in the marketplace, or are observable but have been adjusted based upon various assumptions 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 $361 million and $459 million at December 31, 2014 and 2013, respectively.

ENVIRONMENTAL LIABILITIES AND EXPENDITURES

Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Occidental records environmental reserves and related charges and expenses 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, 2014, 2013 and 2012, Occidental did not have any accruals for reimbursements or recoveries.

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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 may occur.

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

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

ASSET RETIREMENT OBLIGATIONS

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

At a certain number of its facilities, Occidental has identified conditional asset retirement obligations that are related mainly to plant decommissioning. Occidental does not know or cannot estimate when it may settle these obligations. 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 $1,024 million and $1,283 million is included in deferred credits and other liabilities - other, with the remaining current portion in accrued liabilities at December 31, 2014 and 2013, respectively.

For the years ended December 31, (in millions)	2014			2013
Beginning balance	$	1,332		$	1,266
Liabilities incurred – capitalized to PP&E	57			101
Liabilities settled and paid	(78		)	(72		)
Accretion expense	69			68
Acquisitions, dispositions and other – changes in PP&E	(11		)	(10		)
Spin-off of California Resources	(399		)	—
Revisions to estimated cash flows – changes in PP&E	121			(21		)
Ending balance	$	1,091		$	1,332

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 lack of correlation between the hedged item and the hedging instrument due to location, quality, grade or changes in the expected quantity of the hedged item. Gains and losses from derivative

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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, 2014, 2013 and 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.

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 is as follows.

For cash- and stock-settled restricted stock units or incentive award shares (RSUs) and capital employed incentive awards and return on assets (ROCEI/ROAI), compensation value is initially measured on the grant date using the quoted market price of Occidental’s common stock and the estimated payout at the grant date. For total shareholder return incentives (TSRIs), compensation value is initially measured on the grant date using estimated payout levels derived from a Monte Carlo valuation model. Compensation expense for RSUs, ROCEI/ROAI 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 dividends accrued on unvested awards is adjusted quarterly for any changes in stock price and the number of share equivalents expected to be paid based on the relevant performance and market criteria, if applicable. All such performance or stock-price-related changes are recognized in periodic compensation expense. The stock-settled portion of 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 awards are considered participating securities prior to vesting and, therefore, have been deducted from earnings 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, which are more fully described in Note 13, 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 any 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 $2.9 billion, $1.8 billion and $2.3 billion during the years ended December 31, 2014, 2013 and 2012, respectively. Occidental also paid production, property and other taxes of approximately $610 million, $606 million and $524 million during the years ended December 31, 2014, 2013 and 2012, respectively, substantially all of which was in the United States. Interest paid totaled approximately $219 million, $238 million and $190 million, net of capitalized interest of $180 million, $137 million and $100 million, for the years 2014, 2013 and 2012, respectively.

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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

2014

In December 2014, Occidental spent $1.3 billion on an acquisition in the Permian Basin totaling approximately 100,000 net acres. The assets acquired include primarily unproved oil and gas property leases and the related existing lease contracts, permits, licenses, easements, and equipment located on the properties.

On November 30, 2014, the spin-off of California Resources was completed through the pro rata distribution of 81.3 percent of the outstanding shares of common stock of California Resources to holders of Occidental common stock. See Note 17 Spin-off of California Resources.

In November 2014, Occidental entered into an agreement with Plains All American Pipeline, L.P., Plains GP Holdings, L.P. (Plains Pipeline), and Magellan Midstream Partners, L.P. (Magellan) to sell its interest in the BridgeTex Pipeline Company, LLC (BridgeTex), which owns the BridgeTex Pipeline. The sale of Occidental's interest in BridgeTex includes two transactions: Plains Pipeline purchased Occidental's interest in BridgeTex for $1.075 billion, and Magellan acquired Occidental's interest in the southern leg of the BridgeTex Pipeline for $75 million. Occidental recognized a pre-tax gain of $633 million.

Concurrent with the sale of its interest in the BridgeTex Pipeline Company, LLC, Occidental sold a portion of Plains Pipeline for pre-tax proceeds of $1.7 billion, resulting in a pre-tax gain of $1.4 billion.

In February 2014, Occidental entered into an agreement to sell its Hugoton Field operations in Kansas, Oklahoma and Colorado for pre-tax proceeds of $1.4 billion. The transaction was completed in April 2014 and, after taking into account purchase price adjustments, it resulted in pre-tax proceeds of $1.3 billion. Occidental recorded a pre-tax gain on sale of $531 million.

2013

During the year ended December 31, 2013, Occidental paid approximately $0.5 billion to acquire certain domestic oil and gas properties.

In October 2013, Occidental sold a portion of its equity interest in Plains Pipeline for approximately $1.4 billion, resulting in a pre-tax gain of approximately $1.0 billion. In addition, Occidental and Mexichem, S.A.B. de C.V. (Mexichem) formed Ingleside Ethylene, LLC (Ingleside) to build and operate an ethane steam cracking unit capable of producing 1.2 billion pounds of ethylene per year (Cracker), which is expected to begin operating in 2017. With the ethylene produced from the Cracker, Occidental will produce vinyl chloride monomer (VCM), of which Mexichem has contracted to purchase a substantial majority. As of December 31, 2013, Occidental had invested approximately $23 million in Ingleside for its portion of construction costs.

In May 2013, Occidental sold its investment in Carbocloro, a Brazilian chemical facility. Occidental received net proceeds of approximately $270 million and recorded a pre-tax gain of $131 million.

Dr. Ray Irani submitted his resignation as a director, effective as of May 15, 2013, and ceased serving as an executive of Occidental. In addition, certain other employees and several consulting arrangements were terminated during the second quarter. As a result of these developments and actions, Occidental recorded a $55 million pre-tax charge in the second quarter for the estimated costs of Dr. Irani's employment and post-employment benefits, and the termination of other employees and consulting arrangements. Dr. Irani and Occidental have settled all matters relating to his separation. The cost of the settlement was consistent with the estimated charge recorded in the second quarter. Dr. Irani's employment terminated in December 2013.

2012

During the year ended December 31, 2012, Occidental paid approximately $1.9 billion for domestic oil and gas properties in the Permian Basin, Williston Basin and South Texas.

In November 2012, Occidental and Magellan formed BridgeTex Pipeline Company, LLC to construct the BridgeTex Pipeline, which began service in the second half of 2014.

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NOTE 3 ACCOUNTING AND DISCLOSURE CHANGES

RECENTLY ADOPTED ACCOUNTING AND DISCLOSURE CHANGES

In January 2015, the Financial Accounting Standards Board (FASB) issued rules which eliminate from GAAP the concept of extraordinary item. The presentation and disclosure guidance for items that are unusual in nature or occur infrequently will be retained and will be expanded to include items that are both unusual in nature and infrequently occurring. The rules are not expected to have an impact on Occidental’s financial statements upon adoption.

In June 2014, the FASB issued rules affecting entities that grant their employees share-based payment awards in which the terms of the awards provide that a performance target can be achieved after the requisite service period. The new rules require that a performance target that affects vesting and that could be achieved after the requisite service period be treated as a performance condition. Entities may apply the update either: (a) prospectively to all awards granted or modified after the effective date; or (b) retrospectively to all awards with performance targets that are outstanding as of the beginning of the earliest annual period presented in the financial statements and to all new or modified awards thereafter. These rules are effective for annual periods beginning on or after December 15, 2015. The rules are not expected to have a material impact on Occidental's financial statements upon adoption but will require assessment on an ongoing basis.

In May 2014, the FASB issued rules relating to revenue recognition. Under the new rules, an entity will recognize revenue when it transfers promised goods or services to customers in an amount that reflects what it expects to receive in exchange for the goods or services. The rules also require more detailed disclosures related to the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. These rules are effective for the Company for interim and annual periods beginning after December 15, 2016. The rules are not expected to have a material impact on Occidental's financial statements upon adoption.

In April 2014, the FASB issued rules changing the requirements for reporting discontinued operations so that only the disposals of components of an entity that represent a strategic shift that has (or will have) a major effect on an entity's operations and financial results will be reported as discontinued operations in the financial statements. These rules are effective for annual periods beginning on or after December 15, 2014. The rules are not expected to have a material impact on Occidental's financial statements upon adoption.

In July 2013, the FASB issued rules requiring net, rather than gross, presentation of a deferred tax asset for a net operating loss or other tax credit and any related liability for unrecognized tax benefits. The rules became effective on January 1, 2014, and did not have a material impact on Occidental's financial statements.

NOTE 4 INVENTORIES

Net carrying values of inventories valued under the LIFO method were approximately $199 million and $205 million at December 31, 2014 and 2013, respectively. Inventories consisted of the following:

Balance at December 31, (in millions)	2014			2013
Raw materials	$	71		$	74
Materials and supplies	585			628
Finished goods	485			589
	1,141			1,291
Revaluation to LIFO	(89		)	(91		)
Total	$	1,052		$	1,200

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NOTE 5 LONG-TERM DEBT

Long-term debt consisted of the following:

Balance at December 31, (in millions)	2014			2013
1.75% senior notes due 2017	$	1,250		$	1,250
4.10% senior notes due 2021	1,249			1,249
2.70% senior notes due 2023	1,191			1,224
3.125% senior notes due 2022	813			887
4.125% senior notes due 2016	750			750
2.5% senior notes due 2016	700			700
1.50% senior notes due 2018	500			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 (0.04% as of December 31, 2014 and 2013)	68			68
8.75% medium-term notes due 2023	22			22
	6,857			6,964
Less:
Unamortized discount, net	(19		)	(25		)
Current maturities	—			—
Total	$	6,838		$	6,939

Occidental has a bank credit facility (Credit Facility) with a $2.0 billion commitment expiring in 2019. 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 0.07 percent in 2014 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, 2014, 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 2014, Occidental repurchased approximately $107 million of various senior notes due in 2022 and later.

In December 2013, all $600 million of the outstanding 1.45-percent senior notes due 2013 matured. In addition, Occidental repurchased approximately $90 million of various senior notes due in 2021 and later.

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 has provided guarantees on Dolphin Energy's debt, which are limited to certain political and other events. At December 31, 2014 and 2013, Occidental’s total guarantees were not material and a substantial majority of the amounts consisted of limited recourse guarantees on approximately $336 million and $354 million, respectively, of Dolphin’s debt. The fair value of the guarantees was immaterial.

Occidental has guaranteed certain obligations of its subsidiaries for various letters of credit, indemnities and commitments. Marketing guarantees provided to third parties for California Resources total approximately $161 million as of December 31, 2014. The fair value of the marketing guarantees and other obligations of California Resources guaranteed by Occidental were immaterial.

At December 31, 2014, principal payments on long-term debt aggregated approximately $6.9 billion, of which none is due in 2015, $1.5 billion is due in 2016, $1.3 billion is due in 2017, $0.5 billion is due in 2018, $0.1 billion is due in 2019 and $3.5 billion is due in 2020 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, 2014 and 2013, substantially all of which were classified as Level 1, were approximately $7.0 billion and $7.1 billion, respectively, compared to carrying values of approximately $6.9 billion and $7.0 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, 2014 and 2013, variable-rate debt constituted approximately one percent of Occidental's total debt.

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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 the Company to pay for utilities, taxes, insurance and maintenance expenses. At December 31, 2014, 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
2015	$	192
2016	169
2017	161
2018	168
2019	104
Thereafter	592
Total minimum lease payments	$	1,386

Rental expense for operating leases, net of sublease rental income for continuing operations, was $155 million in 2014, $196 million in 2013 and $165 million in 2012. Rental expense was net of sublease income of $4 million in 2014, $3 million in 2013 and $4 million in 2012.

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 obtain the average prices for the relevant production month 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.

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

Cash-Flow Hedges

Occidental’s marketing and trading operations, from time to time, store natural gas purchased from third parties at Occidental’s North American leased storage facilities. Derivative instruments used to fix margins on the future sales of the stored volumes ended March 31, 2014. As of December 31, 2014, Occidental did not have any cash-flow hedges on stored volumes of natural gas. At December 31, 2013, Occidental had approximately 11 billion cubic feet of natural gas held in storage, and had cash-flow hedges for the forecast sale, to be settled by physical delivery, of approximately 13 billion cubic feet of stored natural gas.

The following table presents the 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, 2014 and 2013:

	After-tax
As of December 31, (in millions)	2014			2013
Unrealized losses recognized in AOCI	$	(5	)	$	(3	)
Losses (Gains) reclassified to income	$	8		$	(4	)

Occidental reclassified all of the outstanding balances as of 2013 net after-tax derivative losses from AOCI into net sales during 2014. The amount of the ineffective portion of cash-flow hedges was immaterial for the years ended December 31, 2014 and 2013.

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Derivatives Not Designated as Hedging Instruments

The following table summarizes Occidental's net volumes of outstanding commodity derivatives contracts not designated as hedging instruments, including both financial and physical derivative contracts as of December 31, 2014 and 2013:

	Net Outstanding Position Long / (Short)
Commodity	2014		2013
Oil (million barrels)	(9	)	(22	)
Natural gas (billion cubic feet)	(32	)	(10	)
CO2 (million cubic feet)	621		—

The volumes in the table above exclude contracts tied to index prices, for which the fair value, if any, is minimal at any point in time. These contracts do not expose Occidental to price risk because the contract prices fluctuate with index prices.

Occidental fulfills its short positions through its own production or by third-party purchase contracts. Subsequent to December 31, 2014, 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 $71 million net loss and $11 million net gain from derivatives not designated as hedging instruments were recognized in net sales for the years ended December 31, 2014 and 2013, respectively.

Fair Value of Derivatives

The following table presents the gross and net fair values of Occidental’s outstanding derivatives as of December 31, 2014 and 2013:

(in millions)
December 31, 2014	Asset Derivatives Balance Sheet Location	Fair Value			Liability Derivatives Balance Sheet Location	Fair Value
Cash-flow hedges (a)
Commodity contracts	Other current assets	$	—		Accrued liabilities	$	—
	Long-term receivables and other assets, net	—			Deferred credits and other liabilities	—
		$	—			$	—
Derivatives not designated as hedging instruments (a)
Commodity contracts	Other current assets	$	828		Accrued liabilities	$	886
	Long-term receivables and other assets, net	11			Deferred credits and other liabilities	110
		839				996
Total gross fair value		839				996
Less: counterparty netting and cash collateral (b) (d)		(742		)		(756		)
Total net fair value of derivatives		$	97			$	240

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(in millions)
December 31, 2013	Asset Derivatives Balance Sheet Location	Fair Value			Liability Derivatives Balance Sheet Location	Fair Value
Cash-flow hedges (a)
Commodity contracts	Other current assets	$	—		Accrued liabilities	$	4
	Long-term receivables and other assets, net	—			Deferred credits and other liabilities	—
		$	—			$	4
Derivatives not designated as hedging instruments (a)
Commodity contracts	Other current assets	$	367		Accrued liabilities	$	407
	Long-term receivables and other assets, net	13			Deferred credits and other liabilities	11
		380				418
Total gross fair value		380				422
Less: counterparty netting and cash collateral (c) (d)		(329		)		(364		)
Total net fair value of derivatives		$	51			$	58

(a) Fair values are presented at gross amounts, including when the derivatives are subject to master netting arrangements and presented on a net basis in the consolidated balance sheets.

(b) As of December 31, 2014, collateral received of zero has been netted against derivative assets and collateral paid of $8 million has been netted against derivative liabilities.

(c) As of December 31, 2013, collateral received of $11 million has been netted against derivative assets and collateral paid of $46 million has been netted against derivative liabilities.

(d) Select clearinghouses and brokers require Occidental to post an initial margin deposit. Collateral, mainly for initial margin, of $44 million and $103 million as of December 31, 2014 and 2013, respectively, deposited by Occidental, has not been reflected in these derivative fair value tables. This collateral is included in other current assets in the consolidated balance sheets.

See Note 15 for fair value measurement disclosures on derivatives.

Credit Risk

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

Certain of Occidental's OTC derivative instruments contain credit-risk-contingent features, primarily tied to credit ratings for Occidental or its counterparties, which may affect the amount of collateral that each would need to post. As of December 31, 2014 and 2013, Occidental had a net liability of $4 million and $8 million, respectively, which are net of collateral posted of $3 million and $23 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, 2014 and 2013.

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, 2014, 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.

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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, 2014, Occidental participated in or monitored remedial activities or proceedings at 145 sites, excluding seven sites transferred to California Resources prior to December 31, 2014. The following table presents Occidental’s environmental remediation reserves as of December 31, 2014, 2013 and 2012, the current portion of which is included in accrued liabilities ($79 million in 2014, $78 million in 2013 and $80 million in 2012) and the remainder in deferred credits and other liabilities — other ($255 million in 2014, $252 million in 2013 and $264 million in 2012). The reserves are grouped as environmental remediation sites listed or proposed for listing by the U.S. Environmental Protection Agency on the CERCLA National Priorities List (NPL sites) and three categories of non-NPL sites — third-party sites, Occidental-operated sites and closed or non-operated Occidental sites.

($ amounts in millions)	2014			2013			2012
	Number of Sites	Reserve Balance		Number of Sites	Reserve Balance		Number of Sites	Reserve Balance
NPL sites	30	$	23	31	$	25	35	$	54
Third-party sites	67	101		74	83		75	84
Occidental-operated sites	17	107		20	118		22	123
Closed or non-operated Occidental sites	31	103		32	104		29	83
Total	145	$	334	157	$	330	161	$	344

As of December 31, 2014, Occidental’s environmental reserves exceeded $10 million each at 11 of the 145 sites described above, and 98 of the sites had reserves from $0 to $1 million each.

As of December 31, 2014, two sites — a landfill in western New York owned by Occidental and a former refinery in Louisiana — accounted for 62 percent of its reserves associated with NPL sites. In connection with a 1986 acquisition, Maxus Energy Corporation has retained the liability and is indemnifying Occidental for 14 of the remaining NPL sites.

As of December 31, 2014, Maxus has also retained the liability and is indemnifying Occidental for 8 of the 67 third-party sites. Four of the remaining 59 third-party sites — a former copper mining and smelting operation in Tennessee, a containment and removal project in Tennessee, a former chemical plant in Ohio and an active refinery in Louisiana where Occidental reimburses the current owner for certain remediation activities — accounted for 56 percent of Occidental’s reserves associated with these sites.

Four sites — chemical plants in Kansas, Louisiana and New York and a group of oil and gas properties in the southwestern United States — accounted for 62 percent of the reserves associated with the Occidental-operated sites.

Four other sites — a landfill in western New York, former chemical plants in Tennessee and Delaware and a closed coal mine in Pennsylvania — accounted for 63 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)	2014			2013			2012
Balance — Beginning of Year	$	330		$	344		$	360
Remediation expenses and interest accretion	79			60			56
Spin-off of California Resources	(7		)	—			—
Payments	(68		)	(74		)	(72		)
Balance — End of Year	$	334		$	330		$	344

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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 three to 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 $380 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)	2014		2013		2012
Operating Expenses
Oil and Gas	$	103	$	100	$	116
Chemical	80		75		70
Midstream and Marketing	11		13		13
	$	194	$	188	$	199
Capital Expenditures
Oil and Gas	$	143	$	67	$	79
Chemical	35		14		18
Midstream and Marketing	11		5		8
	$	189	$	86	$	105
Remediation Expenses
Corporate	$	79	$	60	$	56

Operating expenses are incurred on a continual basis. Capital expenditures relate to longer-lived improvements in properties currently operated by Occidental. 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 or disposed assets with respect to which a third party or Occidental retains liability or indemnifies the other party for conditions that existed prior to the transaction.

Occidental has entered into a written settlement agreement with the State of New Jersey (the State) to resolve claims asserted by the State against Occidental arising from Occidental’s acquisition of Diamond Shamrock Chemicals Company (DSCC) and historic operations of DSCC’s Lister Avenue Plant. In December 2014, the settlement was approved by the court. Under the settlement agreement (State Settlement) Occidental will pay the State $190 million and, under certain circumstances, perform or fund future work on behalf of the State along a portion of the Passaic River. When Occidental acquired the stock of DSCC in 1986, Maxus Energy Corporation, a subsidiary of YPF S.A. (Maxus), retained liability for the Lister Avenue Plant, which is part of the Diamond Alkali Superfund Site, as well as other sites. Maxus is also obligated to indemnify Occidental for the State of New Jersey settlement. Occidental is pursuing Maxus to recover the settlement costs. The State Settlement does not cover any potential Occidental share of costs associated with the EPA’s proposed clean-up plan of the Passaic River announced in April 2014. Maxus is also responsible for federal clean-up or other costs associated with the Lister Avenue Plant and the Diamond Alkali Superfund Site.

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, 2014 and 2013 were not material to Occidental's consolidated balance sheets. Occidental also evaluates the amount of reasonably possible losses that it could incur as a result of the matters mentioned above. Occidental has disclosed its range of reasonably possible additional losses for sites where it is a participant in environmental remediation. Occidental believes that other reasonably possible losses that it could incur in excess of reserves accrued on the balance sheet would not be material to its consolidated financial position or results of operations.

During the course of its operations, Occidental is subject to audit by tax authorities for varying periods in various federal, state, local and foreign tax jurisdictions. Although taxable years through 2009 for United States federal income tax purposes have been audited by the United States Internal Revenue Service (IRS) pursuant to its Compliance Assurance Program, subsequent taxable years are currently under review. Additionally, in December 2012, Occidental filed United States federal

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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, 2014, total purchase obligations were $10 billion, which included approximately $3.3 billion, $1.7 billion, $1.0 billion, $0.7 billion and $0.5 billion that will be paid in 2015, 2016, 2017, 2018 and 2019, respectively. Included in the purchase obligations are commitments for major fixed and determinable capital expenditures during 2015 and thereafter, which were approximately $1.4 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, 2014, 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 were as follows:

For the years ended December 31, (in millions)	Domestic			Foreign		Total
2014	$	(732	)	$	2,273	$	1,541
2013	$	3,399		$	4,747	$	8,146
2012	$	852		$	5,636	$	6,488

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
2014
Current	$	870		$	81		$	1,912		$	2,863
Deferred	(1,037		)	(71		)	(70		)	(1,178		)
	$	(167	)	$	10		$	1,842		$	1,685
2013
Current	$	113		$	17		$	2,170		$	2,300
Deferred	883			48			(17		)	914
	$	996		$	65		$	2,153		$	3,214
2012
Current	$	(308	)	$	4		$	2,383		$	2,079
Deferred	519			20			41			580
	$	211		$	24		$	2,424		$	2,659

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,	2014		2013		2012
United States federal statutory tax rate	35	%	35	%	35	%
Other than temporary loss on available for sale investment in California Resources stock	12		—		—
Operations outside the United States	65		5		6
State income taxes, net of federal benefit	1		1		1
Other	(4	)	(1	)	(1	)
Worldwide effective tax rate	109	%	40	%	41	%

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The tax effects of temporary differences resulting in deferred income taxes at December 31, 2014 and 2013 were as follows:

	2014					2013
Tax effects of temporary differences (in millions)	Deferred Tax Assets			Deferred Tax Liabilities		Deferred Tax Assets			Deferred Tax Liabilities
Property, plant and equipment differences	$	—		$	4,081	$	—		$	8,363
Equity investments, partnerships and foreign subsidiaries	—			—		—			225
Environmental reserves	123			—		121			—
Postretirement benefit accruals	379			—		376			—
Deferred compensation and benefits	208			—		222			—
Asset retirement obligations	307			—		407			—
Foreign tax credit carryforwards	1,765			—		1,091			—
Federal benefit of state income taxes	85			—		136			—
All other	274			221		344			82
Subtotal	3,141			4,302		2,697			8,670
Valuation allowance	(1,744		)	—		(1,074		)	—
Total deferred taxes	$	1,397		$	4,302	$	1,623		$	8,670

The current portion of total deferred tax assets was$110 million and $150 million as of December 31, 2014 and 2013, respectively, which was reported in other current assets. Total deferred tax assets were $1.4 billion and $1.6 billion as of December 31, 2014 and 2013, 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. The reduction in net deferred tax liabilities from 2013 to 2014 was primarily due to the spin-off of California Resources. See Note 17 Spin-off of California Resources.

Occidental had, as of December 31, 2014, foreign tax credit carryforwards of $1.8 billion, which expire in varying amounts through 2024, and various state operating loss carryforwards, which have varying carryforward periods through 2025. Occidental's valuation allowance provides for substantially all of the 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 $9.9 billion, net of foreign taxes, at December 31, 2014, 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 $140 million would be required, assuming utilization of available foreign tax credits.

Discontinued operations include income tax charges of $454 million, $550 million and $466 million in 2014, 2013 and 2012, respectively.

Additional paid-in capital was credited $4 million in 2014, $6 million in 2013 and $8 million in 2012 for an excess tax benefit from the exercise of certain stock-based compensation awards.

As of December 31, 2014, Occidental had liabilities for unrecognized tax benefits of approximately $61 million included in deferred credits and other liabilities – other, all of which, if subsequently recognized, would favorably affect Occidental’s effective tax rate.

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

For the years ended December 31, (in millions)	2014		2013
Balance at January 1,	$	61	$	76
Reductions based on tax positions related to prior years and settlements	—		(15		)
Balance at December 31,	$	61	$	61

Management believes it is unlikely that Occidental’s liabilities for unrecognized tax benefits related to existing matters would increase or decrease within the next 12 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. 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, 2014, 2013 and 2012.

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

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NOTE 11 STOCKHOLDERS' EQUITY

The following is a summary of common stock issuances:

Shares in thousands	Common Stock
Balance, December 31, 2011	886,809
Issued	1,746
Options exercised and other, net	246
Balance, December 31, 2012	888,801
Issued	826
Options exercised and other, net	292
Balance, December 31, 2013	889,919
Issued	584
Options exercised and other, net	55
Balance, December 31, 2014	890,558

TREASURY STOCK

On October 2, 2014, Occidental increased the total number of shares authorized for its share repurchase program by 60 million shares to 185 million shares total; however, the program does not obligate Occidental to acquire any specific number of shares and may be discontinued at any time. In 2014 and 2013, respectively, Occidental purchased 25.8 million and 10.3 million shares under the program at an average cost of $93.40 and $94.42 per share, respectively. Additionally, Occidental purchased shares from the trustee of its defined contribution savings plan during each year. As of December 31, 2014, 2013 and 2012, treasury stock shares numbered 120.0 million, 93.9 million and 83.3 million, respectively.

NONREDEEMABLE PREFERRED STOCK

Occidental has authorized 50,000,000 shares of preferred stock with a par value of $1.00 per share. At December 31, 2014, 2013 and 2012, Occidental had no outstanding shares of preferred stock.

EARNINGS PER SHARE

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

(in millions, except per-share amounts)	2014			2013			2012
Basic EPS
(Loss) / Income from continuing operations	$	(130	)	$	4,932		$	3,829
Less: Income from continuing operations attributable to noncontrolling interest	(14		)	—			—
(Loss) / Income from contributing operations attributable to common stock	(144		)	4,932			3,829
Discontinued operations, net	760			971			769
Net income	616			5,903			4,598
Less: Net income allocated to participating securities	—			(13		)	(8		)
Net income, net of participating securities	$	616		$	5,890		$	4,590
Weighted average number of basic shares	781.1			804.1			809.3
Basic EPS	$	0.79		$	7.33		$	5.67
Diluted EPS
Net income, net of participating securities	$	616		$	5,890		$	4,590
Weighted average number of basic shares	781.1			804.1			809.3
Dilutive securities	—			0.5			0.7
Total diluted weighted average common shares	781.1			804.6			810.0
Diluted EPS	$	0.79		$	7.32		$	5.67

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ACCUMULATED OTHER COMPREHENSIVE LOSS

Accumulated other comprehensive loss consisted of the following after-tax amounts:

Balance at December 31, (in millions)	2014			2013
Foreign currency translation adjustments	$	(7	)	$	(5	)
Unrealized losses on derivatives	(11		)	(14		)
Pension and post-retirement adjustments (a)	(339		)	(284		)
Total	$	(357	)	$	(303	)

(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 including in the form of RSUs, stock options (Options), stock appreciation rights (SARs), ROCEI/ROAI and TSRIs. An aggregate of 66 million shares of Occidental common stock were authorized for issuance and approximately 17 million shares had been issued through December 31, 2014. Of the remaining shares, only approximately 20 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 are available for future awards. Accordingly, the number of shares available for future awards may be less than 20 million depending on the type of award granted. Additionally, under the plan, the shares available for future awards may increase, depending on the award type, 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 canceled, or (iii) correspond to the portion of any stock-based awards settled in cash.

During 2014, non-employee directors were granted awards for 28,283 shares of common stock. 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.

California Resources Spin-off Adjustments

In connection with the separation of California Resources, Occidental entered into an Employee Matters Agreement with California Resources, which provided that employees of California Resources no longer participate in incentive programs sponsored or maintained by Occidental. Pursuant to the Employee Matters Agreement, Occidental made certain adjustments, using volumetric weighted-average prices for the 4-day period immediately prior to and immediately following the separation, to the exercise price and number of share-based compensation awards, with the intention of preserving the intrinsic value of the awards immediately prior to the separation for all Occidental employees. These adjustments are summarized as follows:

Ø Any unvested long-term incentive award units or shares, including Total Shareholder Return Incentives (TSRI), Return on Capital Employed Incentives (ROCEI), Return on Asset Incentives (ROAI), Restricted Stock Incentives (RSI), Long-Term Incentives (LTI) and Phantom Share Units (PHSU) were adjusted by multiplying the pre-spin number of units held by the quotient of the simple average of the volume weighted average price per share of Oxy stock for the four trading days immediately prior to and the four trading days immediate after the date of spin-off. Post-spin units were rounded up to the next whole number.

Ø For outstanding option awards, the strike price was adjusted (reduced) by the same quotient as described above.

Ø Performance periods, performance targets and vesting dates of Long-Term Incentive awards were not adjusted.

Ø Pursuant to the terms of all outstanding TSRI awards, the spin-off was treated as a dividend.

The separation-related adjustments did not have a material impact on either compensation expense for the year ended December 31, 2014, or the number of potentially dilutive securities as of December 31, 2014.

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The following table summarizes total share-based compensation expense recognized in income related to continuing and discontinued operations and the associated tax benefit for the years ended December 31:

For the years ended December 31, (in millions)	2014		2013		2012
Compensation expense	$	129	$	152	$	78
Income tax benefit recognized in the income statement	46		55		29
Intrinsic value of options and stock-settled SARs exercised	5		24		18
Cash paid (a)	95		96		83
Fair value of RSUs and TSRIs vested during the year (b)	56		83		28

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

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

As of December 31, 2014, unrecognized compensation expense for all unvested stock-based incentive awards was $160 million. This expense is expected to be recognized over a weighted-average period of 2.0 years.

RSUs

Certain employees are awarded the right to receive RSUs, some of which have performance criteria, and are in the form of, or equivalent in value to, actual shares of Occidental common stock. Depending on their terms, RSUs are settled in cash or stock at the time of vesting. These awards vest ratably over three years, or at the end of two or three years, following the grant date, however, certain of the RSUs are forfeitable if performance objectives are not satisfied by the seventh anniversary of the grant date. For certain three-year RSUs, dividend equivalents are paid during the vesting period. For those awards that cliff vest in two or three years, dividend equivalents are accumulated during the vesting period and are paid when they vest.

The weighted-average, grant-date fair values of cash-settled RSUs granted in 2014, 2013 and 2012 were $100.95, $89.70, and $84.38 per share, respectively. The weighted-average, grant-date fair values of the stock-settled RSUs granted in 2014, 2013, and 2012 were $101.77, $90.35 and $84.81, respectively.

A summary of changes in Occidental’s unvested cash- and stock-settled RSUs during the year ended December 31, 2014 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	1,431			$	90.12	1,607			$	90.26
Granted	726			100.95		785			101.77
Vested	(641	)		92.46		(553	)		94.34
Shares issued upon California Resources spin-off	76			—		95			—
Shares forfeited by employees of California Resources	(396	)		90.70		(412	)		93.30
Forfeitures	(79	)		91.00		(97	)		92.13
Unvested at December 31	1,117			89.42		1,425			88.98

TSRIs

Certain executives are awarded TSRIs that vest at the end of a three-year period following the grant date if performance targets are certified as being met. TSRIs granted in July 2014 and 2013 have payouts that range from 0 to 150 percent of the target award; TSRIs granted in 2012 have payouts that range from 0 to 100 percent of the maximum award. All outstanding TSRIs settle fully in stock once certified. Dividend equivalents for TSRIs are accumulated and 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.

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

	TSRIs
Year Granted	2014			2013			2012
Assumptions used:
Risk-free interest rate	1.0		%	0.6		%	0.4		%
Dividend yield	2.8		%	2.8		%	2.6		%
Volatility factor	27		%	30		%	34		%
Expected life (years)	3			3			3
Grant-date fair value of underlying Occidental common stock	$	101.95		$	91.97		$	84.57

A summary of Occidental’s unvested TSRIs as of December 31, 2014, and changes during the year ended December 31, 2014, is presented below:

	TSRIs
	Awards (000’s)		Weighted-Average Grant-Date Fair Value of Occidental Stock
Unvested at January 1 (a)	832			$	92.49
Granted (a)	106			101.95
Vested (a)	(300	)		102.97
Forfeitures	(16	)		90.65
Shares issued upon California Resources spin-off	33			—
Shares forfeited by employees of California Resources	(82	)		87.28
Unvested at December 31 (a)	573			84.22

(a) Presented at the target or mid-point payouts.

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. 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 US Treasury Strips 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.

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The following is a summary of Option and SAR transactions during the year ended December 31, 2014:

	Cash-Settled							Stock-Settled
	SARs (000's)		Weighted- Average Exercise Price		Weighted- Average Remaining Contractual Term (yrs)	Aggregate Intrinsic Value (000’s)		SARs & Options (000's)		Weighted- Average Exercise Price		Weighted- Average Remaining Contractual Term (yrs)	Aggregate Intrinsic Value (000’s)
Beginning balance, January 1	352		$	24.66				145		$	42.11
Exercised	(352	)	$	24.66				(87	)	$	38.00
Shares issued upon California Resources spin-off	—		$	—				3		$	47.87
Ending balance, December 31	—		$	—	—	$	—	61		$	45.78	1.3	$	2,125
Exercisable at December 31	—		$	—	—	$	—	61		$	45.78	1.3	$	2,125

ROCEI / ROAI

During 2014, Occidental also granted approximately 141,000 share-equivalents to certain employees that vest at the end of a three-year period beginning January 1, 2015, if performance targets based on return on assets of the applicable segment or return on capital employed are certified as being met. These awards are settled in stock at the time of vesting, with payouts that range from 0 to 200 percent of the target award. Dividend equivalents are accumulated and paid upon vesting for the number of vested shares.

	ROCEI / ROAI
	Awards (000's)		Weighted-Average Grant-Date Fair Value of Occidental Stock
Unvested at January 1	158			$	91.90
Granted	141			101.95
Shares issued upon California Resources spin-off	16			—
Shares forfeited by employees of California Resources	(33	)		87.28
Unvested at December 31	282			92.25

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 $163 million and $166 million as of December 31, 2014 and 2013, respectively, and Occidental expensed $146 million in 2014, $140 million in 2013 and $137 million in 2012 under the provisions of these defined contribution and supplemental retirement plans.

DEFINED BENEFIT PLANS

Participation in defined benefit plans is limited and approximately 700 domestic and 1,300 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.

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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 $215 million in 2014, $229 million in 2013 and $218 million in 2012.

SPIN-OFF OF CALIFORNIA RESOURCES

In connection with the spin-off of California Resources, Occidental entered into an Employee Matters Agreement with California Resources, see Note 17, which provides that employees of California Resources no longer participate in benefit plans sponsored or maintained by Occidental as of the separation date. Upon separation, the Occidental pension and postretirement plans transferred assets and obligations to the California Resources plans resulting in a net decrease in sponsored pension and postretirement plan obligations of $15 million and $72 million, respectively. Additionally, as a result of the transfer of unrecognized losses to California Resources, deferred income taxes and other comprehensive income decreased $14 million and $36 million, respectively.

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,	2014			2013			2014			2013
Amounts recognized in the consolidated balance sheet:
Other assets	$	57		$	104		$	—		$	—
Accrued liabilities	(6		)	(6		)	(57		)	(58		)
Deferred credits and other liabilities — other	(68		)	(83		)	(980		)	(958		)
	$	(17	)	$	15		$	(1,037	)	$	(1,016	)
AOCI included the following after-tax balances:
Net loss	$	83		$	66		$	255		$	225
Prior service cost	—			1			1			2
	$	83		$	67		$	256		$	227
For the years ended December 31,
Changes in the benefit obligation:
Benefit obligation — beginning of year	$	523		$	615		$	1,016		$	1,127
Service cost — benefits earned during the period	11			13			24			29
Interest cost on projected benefit obligation	23			24			44			43
Actuarial (gain) loss	53			(35		)	83			(126		)
Foreign currency exchange rate (gain) loss	(9		)	(5		)	—			—
Spin-off of California Resources	(105		)	—			(72		)	—
Benefits paid	(43		)	(54		)	(59		)	(57		)
Settlements	—			(35		)	—			—
Benefit obligation — end of year	$	453		$	523		$	1,036		$	1,016
Changes in plan assets:
Fair value of plan assets — beginning of year	$	538		$	499		$	—		$	—
Actual return on plan assets	24			88			—			—
Employer contributions	7			29			—			—
Spin-off of California Resources	(90		)	—			—			—
Benefits paid	(43		)	(54		)	—			—
Settlements	—			(24		)	—			—
Fair value of plan assets — end of year	$	436		$	538		$	—		$	—
Funded/(Unfunded) status:	$	(17	)	$	15		$	(1,036	)	$	(1,016	)

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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,	2014		2013		2014		2013
Projected Benefit Obligation	$	173	$	122	$	280	$	401
Accumulated Benefit Obligation	$	168	$	112	$	280	$	386
Fair Value of Plan Assets	$	100	$	39	$	336	$	499

Occidental does not expect any plan assets to be returned during 2015.

COMPONENTS OF NET PERIODIC BENEFIT COST

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

	Pension Benefits									Postretirement Benefits
For the years ended December 31, (in millions)	2014			2013			2012			2014		2013		2012
Net periodic benefit costs:
Service cost — benefits earned during the period	$	11		$	13		$	13		$	24	$	29	$	25
Interest cost on projected benefit obligation	23			24			27			44		43		42
Expected return on plan assets	(33		)	(31		)	(31		)	—		—		—
Recognized actuarial loss	6			19			19			20		38		37
Other costs and adjustments	(8		)	(13		)	17			1		1		1
Net periodic benefit cost	$	(1	)	$	12		$	45		$	89	$	111	$	105

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 $10 million and zero, 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 $29 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,	2014			2013		2014		2013
Benefit Obligation Assumptions:
Discount rate	3.81	%		4.45	%	3.99	%	4.75	%
Rate of compensation increase	—		(a)	4.00	%	—		—
Net Periodic Benefit Cost Assumptions:
Discount rate	4.45	%		3.59	%	4.75	%	3.89	%
Assumed long term rate of return on assets	6.50	%		6.50	%	—		—
Rate of compensation increase	4.00	%	(a)	4.00	%	—		—

(a) Plans requiring a salary increase assumption were separated with California Resources.

For domestic pension plans and postretirement benefit plans, Occidental based the discount rate on the Aon/Hewitt AA-AAA Universe yield curve in 2014 and 2013. As of December 31, 2014, the use of a weighted average rate of increase in future compensation levels was not necessary as the retirement plans determining benefits using compensation were transferred in connection with the California Resources spin-off. At December 31, 2013, the weighted average rate of increase in future compensation levels was consistent with Occidental's past and anticipated future compensation increases for employees participating in retirement plans that determine benefits using compensation. The assumed long term rate of return on assets is estimated with regard to current market factors but within the context of historical returns for the asset mix that exists at year end.

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In 2014, Occidental adopted the Society of Actuaries 2014 Mortality Tables Report and Mortality Improvement Scale, which updated the mortality assumptions that private defined benefit retirement plans in the United States use in the actuarial valuations that determine a plan sponsor’s pension obligations. The updated mortality data reflects increasing life expectancies in the United States, and affected plans generally expect the value of the actuarial obligations to increase, depending on the specific demographic characteristics of the plan participants and the types of benefits. The changes in the mortality table results in anincrease of $27 million and $98 million in the pension and postretirement benefit obligation at December 31, 2014.

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 percent at both December 31, 2014 and 2013. The average rate of increase in future compensation levels ranged from 1.5 percent to 10 percent in 2014, depending on local economic conditions.

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 1.79 percent and 2.36 percent as of December 31, 2014 and 2013, 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 0.25 percent per year from 7.75 percent in 2014 until they reach 5.0 percent in 2025, and remain at 5.0 percent thereafter. A 1-percent increase or a 1-percent decrease in these assumed healthcare cost trend rates would result in an increase of $55 million or a reduction of $47 million, respectively, in the postretirement benefit obligation as of December 31, 2014. The annual service and interest costs would not be materially affected by these changes.

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

FAIR VALUE OF PENSION PLAN ASSETS

Occidental employs a total return investment approach that uses a diversified blend of equity and fixed-income investments to optimize the long-term return of plan assets at a prudent level of risk. The investments are monitored by Occidental’s Pension and Retirement Trust and Investment Committee (Pension Committee) in its role as fiduciary. The Pension 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 65 percent equity securities and 35 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, 2014 Using
Description	Level 1		Level 2		Level 3		Total
Asset Class:
U.S. government securities	$	15	$	—	$	—	$	15
Corporate bonds (a)	—		76		—		76
Common/collective trusts (b)	—		13		—		13
Mutual funds:
Bond funds	42		—		—		42
Blend funds	68		—		—		68
Common and preferred stocks (c)	196		—		—		196
Other	—		38		1		39
Total pension plan assets (d)	$	321	$	127	$	1	$	449

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(in millions)	Fair Value Measurements at December 31, 2013 Using
Description	Level 1		Level 2		Level 3		Total
Asset Class:
U.S. government securities	$	16	$	—	$	—	$	16
Corporate bonds (a)	—		84		—		84
Common/collective trusts (b)	—		19		—		19
Mutual funds:
Bond funds	64		—		—		64
Blend funds	105		—		—		105
Value and growth funds	6		—		—		6
Common and preferred stocks (c)	201		—		—		201
Other	—		37		11		48
Total pension plan assets (d)	$	392	$	140	$	11	$	543

(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 $13 million and $5 million as of December 31, 2014 and 2013, respectively.

The activity during the years ended December 31, 2014 and 2013, for the assets using Level 3 fair value measurements was insignificant. Occidental expects to contribute $6 million in cash to its defined benefit pension plans during 2015.

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
2015	$	38	$	58
2016	$	37	$	59
2017	$	33	$	59
2018	$	32	$	59
2019	$	32	$	60
2020— 2024	$	191	$	304

NOTE 14 INVESTMENTS AND RELATED-PARTY TRANSACTIONS

EQUITY INVESTMENTS

As of December 31, 2014 and 2013, investments in unconsolidated entities comprised $1.2 billion and $1.5 billion of equity-method investments, respectively.

As of December 31, 2014, Occidental’s equity investments consisted mainly of a 13-percent interest in 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 $396 million, $447 million, and $526 million to Occidental in 2014, 2013 and 2012, respectively. As of December 31, 2014, cumulative undistributed earnings of equity-method investees since their respective acquisitions was immaterial. As of December 31, 2014, Occidental's investments in equity investees exceeded the underlying equity in net assets by approximately $632 million, of which almost $546 million represented goodwill and the remainder comprised intangibles amortized over their estimated useful lives.

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

For the years ended December 31, (in millions)	2014		2013		2012
Revenues	$	3,090	$	3,373	$	2,667
Costs and expenses	2,774		2,987		2,310
Net income	$	316	$	386	$	357
As of December 31, (in millions)	2014		2013
Current assets	$	1,127	$	1,813
Non-current assets	$	2,925	$	4,412
Current liabilities	$	771	$	1,308
Long-term debt	$	1,701	$	2,506
Other non-current liabilities	$	83	$	163
Stockholders’ equity	$	1,498	$	2,248

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 upstream 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 operates a pipeline and is accounted for as an equity investment.

In November 2014 and October 2013, Occidental sold a portion of its equity interest in Plains Pipeline for approximately $1.7 billion and $1.4 billion, resulting in pre-tax gains of approximately $1.4 billion and $1.0 billion, respectively.

AVAILABLE FOR SALE INVESTMENT IN CALIFORNIA RESOURCES STOCK

As part of Occidental's spin-off of its California oil and gas operations and related assets, Occidental retained an 18.7 percent interest in California Resources stock or approximately 71.5 million shares, which is recorded as an available for sale investment.

As a result of a declining trading price, Occidental recorded an other-than-temporary loss of $553 million for this available for sale investment as of December 31, 2014. At December 31, 2014, Occidental's available for sale investment in California Resources was $394 million.

RELATED-PARTY TRANSACTIONS

From time to time, Occidental purchases oil, NGLs, power, steam and chemicals from and sells oil, NGLs, gas, chemicals and power to certain of its equity investees and other related parties at market-related prices. During 2014, 2013 and 2012, Occidental entered into the following related-party transactions and had the following amounts due from or to its related parties:

For the years ended December 31, (in millions)	2014		2013		2012
Sales (a)	$	835	$	663	$	419
Purchases	$	6	$	—	$	8
Services	$	27	$	30	$	17
Advances and amounts due from	$	26	$	67	$	25
Amounts due to	$	15	$	3	$	129

(a) In 2014, 2013 and 2012, sales of Occidental-produced oil and NGLs to Plains Pipeline accounted for 46 percent, 72 percent and 80 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.

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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:

(in millions)	Fair Value Measurements at December 31, 2014 Using						Netting and Collateral			Total Fair Value
Description	Level 1		Level 2		Level 3
Assets:
Commodity derivatives	$	712	$	127	$	—	$	(742	)	$	97
Available for sale investment	$	394	$	—	$	—	$	—		$	394
Liabilities:
Commodity derivatives	$	750	$	246	$	—	$	(756	)	$	240

(in millions)	Fair Value Measurements at December 31, 2013 Using						Netting and Collateral			Total Fair Value
Description	Level 1		Level 2		Level 3
Assets:
Commodity derivatives	$	185	$	195	$	—	$	(329	)	$	51
Liabilities:
Commodity derivatives	$	199	$	223	$	—	$	(364	)	$	58

FAIR VALUES – NONRECURRING

As a result of the sharp decline of the forward price curve in the fourth quarter of 2014, Occidental recognized approximately $3.8 billion in pre-tax impairment charges related to proved oil and gas properties. Domestically, Occidental recognized $2.8 billion in pre-tax impairment charges related to domestic oil and gas properties primarily in the Williston Basin and gas and NGLs assets. Internationally, the remaining $1.0 billion related primarily to Bahrain.

The impairment tests, including the fair value estimation, incorporated a number of assumptions involving expectations of future cash flows. These assumptions included estimates of future product prices, which Occidental based on forward price curves and, where applicable, contractual prices, estimates of oil and gas reserves, estimates of future expected operating and development costs and a risk adjusted discount rate of 8 percent. These properties were impacted by persistently low natural gas prices and the recent decline in oil prices in the United States changing management's development plans. Occidental used the income approach to measure the fair value of these properties, using inputs categorized as Level 3 in the fair value hierarchy.

In 2014, Occidental recognized approximately $111 million pre-tax charges related to the impairments of Chemical assets.

(in millions)	Fair Value Measurements at December 31, 2014 Using						Net Book Value (a)		Total Pre-tax (Non-cash) Impairment Loss
Description	Level 1		Level 2		Level 3
Assets:
Impaired proved oil and gas assets - domestic	$	—	$	—	$	2,249	$	5,008	$	2,759
Impaired proved oil and gas assets - international	$	—	$	—	$	45	$	1,084	$	1,039
Impaired Chemical property, plant, and equipment	$	—	$	—	$	18	$	129	$	111

(a)Amount represents net book value at date of assessment.

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. See Note 5 for the fair value of Long-term Debt.

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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 power. Additionally, the midstream and marketing segment 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 and restricted cash, certain corporate receivables and PP&E, and an investment in the Joslyn, Canada oil sands project.

Industry Segments
(in millions)	Oil and Gas			Chemical			Midstream and Marketing				Corporate and Eliminations				Total
YEAR ENDED DECEMBER 31, 2014
Net sales	$	13,887	(a)	$	4,817	(b)	$	1,373		(c)	$	(765	)		$	19,312
Pretax operating profit (loss)	$	428	(d)	$	420	(e)	$	2,578		(f)	$	(1,871	)	(g)	$	1,555
Net income attributable to noncontrolling interest	—			—			(14		)		—				(14		)
Income taxes	—			—			—				(1,685		)	(g)	(1,685		)
Discontinued operations, net	—			—			—				760			(i)	760
Net income (loss) attributable to common stock	$	428		$	420		$	2,564			$	(2,796	)		$	616
Investments in unconsolidated entities	$	11		$	202		$	948			$	10			$	1,171
Property, plant and equipment additions, net (k)	$	6,589		$	325		$	2,093			$	103			$	9,110
Depreciation, depletion and amortization	$	3,701		$	367		$	160			$	33			$	4,261
Total assets	$	31,072		$	3,917		$	12,283			$	8,987			$	56,259
YEAR ENDED DECEMBER 31, 2013
Net sales	$	15,008	(a)	$	4,673	(b)	$	1,174		(c)	$	(685	)		$	20,170
Pretax operating profit (loss)	$	6,411	(d)	$	743	(e)	$	1,523		(f)	$	(531	)	(g)	$	8,146
Income taxes	—			—			—				(3,214		)	(h)	(3,214		)
Discontinued operations, net	—			—			—				971			(i)	971
Net income (loss) attributable to common stock	$	6,411		$	743		$	1,523			$	(2,774	)		$	5,903
Investments in unconsolidated entities	$	108		$	34		$	1,307			$	10			$	1,459
Property, plant and equipment additions, net (k)	$	5,456		$	435		$	1,437			$	166			$	7,494
Depreciation, depletion and amortization	$	3,676		$	346		$	149			$	32			$	4,203
Total assets	$	46,213		$	3,947		$	14,374			$	4,909			$	69,443
YEAR ENDED DECEMBER 31, 2012
Net sales	$	14,953	(a)	$	4,580	(b)	$	1,164		(c)	$	(597	)		$	20,100
Pretax operating profit (loss)	$	5,840	(d)	$	720		$	440		(f)	$	(512	)	(g)	$	6,488
Income taxes	—			—			—				(2,659		)	(h)	(2,659		)
Discontinued operations, net	—			—			—				769			(i)	769
Net income (loss) attributable to common stock	$	5,840	(d)	$	720		$	440			$	(2,402	)		$	4,598
Investments in unconsolidated entities	$	113		$	108		$	1,662			$	11			$	1,894
Property, plant and equipment additions, net (k)	$	6,067		$	365		$	1,451			$	91			$	7,974
Depreciation, depletion and amortization	$	3,065		$	345		$	148			$	27			$	3,585
Total assets	$	44,004		$	3,854		$	12,762			$	3,590			$	64,210
(See footnotes on next page)

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Footnotes:

(a) Oil sales represented approximately 90 percent, 91 percent and 91 percent of the oil and gas segment net sales for the years ended December 31, 2014, 2013 and 2012, respectively.

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

	Basic Chemicals	Vinyls	Other Chemicals
Year ended December 31, 2014	54%	43%	3%
Year ended December 31, 2013	55%	42%	3%
Year ended December 31, 2012	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, 2014	49%	31%	20%
Year ended December 31, 2013	54%	30%	16%
Year ended December 31, 2012	60%	24%	16%

(d) The 2014 amount includes pre-tax charges of $4.7 billion for the impairment of domestic oil and gas assets, pre-tax charges of $1.1 billion for the impairment of foreign oil and gas assets, and pre-tax gain of $531 million for the sale of the Hugoton field. The 2013 amount includes pre-tax charges of $607 million for the impairment of domestic non-producing acreage. The 2012 amount includes pre-tax charges of $1.7 billion for the impairment of domestic gas assets and related items.

(e) The 2014 amount includes the pre-tax charge of $149 million. The 2013 amount includes a pre-tax gain of $131 million for the sale of an investment in Carbocloro.

(f) The 2014 amount includes pre-tax gains of $633 million and $1,351 million for the sales of BridgeTex Pipeline and a portion of an investment in Plains Pipeline, respectively, and other charges of $31 million. The 2013 amount includes a pre-tax gain of $1,044 million for the sale of a portion of an investment in Plains Pipeline and other items of $58 million.

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

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

(i) Relates to discontinued operations from Ecuador and the spin-off of California Resources.

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

Benefit (Charge)  (in millions)	2014			2013			2012
CORPORATE
Pre-tax operating profit (loss)
California Resources other than temporary loss	$	(553	)	$	—		$	—
Joslyn Impairment	(805		)	—			—
Spin-off and other costs	(61		)	—			—
Litigation reserves	—			—			(20		)
Charge for former executives and consultants	—			(55		)	—
	$	(1,419	)	$	(55	)	$	(20	)
Income taxes
Tax effect of pre-tax and other adjustments *	$	927		$	(167	)	$	612

* Amounts represent the tax effect of the pre-tax adjustments listed in this note, as well as those in footnotes (d), (e) and (f).

(k)     Includes capital expenditures and capitalized interest, but excludes acquisition and disposition of assets.

GEOGRAPHIC AREAS

(in millions)	Net sales (a)						Property, plant and equipment, net
For the years ended December 31,	2014		2013		2012		2014		2013		2012
United States	$	11,943	$	11,724	$	11,287	$	26,673	$	42,956	$	40,786
Foreign
Qatar	2,803		2,995		3,356		2,605		2,605		2,676
Oman	2,524		2,567		2,578		2,876		2,509		2,353
Colombia	938		1,022		1,027		1,396		1,259		1,041
United Arab Emirates	—		—		—		4,312		3,131		2,104
Other Foreign	1,104		1,862		1,852		1,868		3,361		3,104
Total Foreign	7,369		8,446		8,813		13,057		12,865		11,278
Total	$	19,312	$	20,170	$	20,100	$	39,730	$	55,821	$	52,064

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

74

NOTE 17 SPIN-OFF OF CALIFORNIA RESOURCES CORPORATION

On November 30, 2014, the spin-off of Occidental's California oil and gas operations and related assets was completed through the distribution of 81.3 percent of the outstanding shares of common stock of California Resources, creating an independent, publicly traded company. Occidental shareholders at the close of business on the record date of November 17, 2014 received 0.4 shares of California Resources for every share of Occidental common stock held. Fractional shares of California Resources were not distributed and any fractional shares otherwise issuable to an Occidental shareholder were sold on the open market on such shareholder's behalf, and such shareholder received a cash payment with respect to the fractional share.

In connection with the spin-off, California Resources distributed to Occidental $4.95 billion in restricted cash and $1.15 billion in unrestricted cash. Occidental retained 71.5 million shares in California Resources, see Note 14. The cash distributions were issued using the proceeds from $5 billion in Senior Notes issued by California Resources in October 2014 and borrowings under California Resources' $1.0 billion Term Loan Facility and $2.0 billion Revolving Credit Facility. As indicated by a private letter ruling from the Internal Revenue Service (IRS), the $4.95 billion distribution will be used solely to pay dividends, repurchase common stock, repay debt, or a combination of the foregoing, within eighteen months following the distribution. At December 31, 2014, the remaining balance of the restricted cash distribution was $4.0 billion and was included in the "Restricted cash" line on the consolidated balance sheet.

In order to effect the separation and govern the relationship with California Resources after the spin-off, Occidental and California Resources entered into a Separation and Distribution Agreement, a Stockholder's and Registration Rights Agreement, a Tax Sharing Agreement, an Employee Matters Agreement, a Transition Services Agreement, an Area of Mutual Interest Agreement, a Confidentiality and Trade Secret Protection Agreement, and an Intellectual Property License Agreement.

The Separation and Distribution Agreement and related ancillary agreements govern the transfer of assets and other matters related to the spin-off. The Intellectual Property License Agreement governs the allocation of intellectual property rights and assets between California Resources and Occidental. The Confidentiality and Trade Secret Protection Agreement safeguards confidential and trade information related to Occidental from five years after the spin-off date. The Stockholder's and Registration Rights Agreement governs, among other things, the registration of shares of California Resources. The Area of Mutual Interest Agreement governs the rights and obligations of both California Resources and Occidental for the exploration and development of oil and natural gas interests located within the United States excluding California.

The Tax Sharing Agreement governs the respective rights, responsibilities and obligations of California Resources and Occidental with respect to taxes, tax attributes, tax returns, tax proceedings and certain other tax matters. In addition, the Tax Sharing Agreement imposed certain restrictions on California Resources and its subsidiaries (including restrictions on share issuances, business combinations, sales of assets and similar transactions) that are designed to preserve the tax-free status of the distribution and certain related transactions. The Tax Sharing Agreement sets forth the obligations of California Resources and Occidental as to the filing of tax returns, the administration of tax proceedings and assistance and cooperation on tax matters.

The Employee Matters Agreement governs the compensation and employee benefit obligations with respect to the current and former employees and non-employee directors of California Resources and Occidental, and generally allocates liabilities and responsibilities relating to employee compensation, benefit plans and programs. The Employee Matters Agreement provides that employees of California Resources will no longer participate in benefit plans sponsored or maintained by Occidental. In addition, the Employee Matters Agreement provides that each of the parties will be responsible for their respective current employees and compensation plans for such current employees, and Occidental will be responsible for liabilities relating to former employees who left prior to the separation (other than in certain instances where a plan or program was sponsored by a company that became part of the California Resources group of companies at the separation). The Employee Matters Agreement sets forth the general principles relating to employee matters and also addresses any special circumstances during the transition period. The Employee Matters Agreement also provides that (i) the distribution does not constitute a change in control under existing plans, programs, agreements or arrangements, and (ii) the distribution and the assignment, transfer or continuation of the employment of employees with another entity will not constitute a severance event under the applicable plans, programs, agreements or arrangements.

The Transition Services Agreement sets forth the terms on which Occidental will provide California Resources, and California Resources will provide to Occidental, certain services or functions California Resources and Occidental historically have shared. Transition services include administrative, payroll, human resources, data processing, environmental health and safety, financial audit support, financial transaction support, information technology systems and various other corporate services. The agreement provides for the provision of specified transition services, generally for a period of up to 24 months on a cost or a cost-plus basis.

75

The following table presents the carrying value of major categories of assets and liabilities of California Resources immediately preceding the spin-off at November 30, 2014 and at December 31, 2013:

(in millions)	November 30, 2014			December 31, 2013
CURRENT ASSETS
Cash and cash equivalents	$	8		$	—
Accounts receivables, net	591			30
Inventories	73			75
Other current assets	22			125
Total current assets	694			230
Total property, plant, and equipment	23,257			21,065
Accumulated depreciation, depletion, and amortization	(8,079		)	(6,974		)
	15,178			14,091
LONG-TERM RECEIVABLES AND OTHER ASSETS, NET	112			35
TOTAL ASSETS	$	15,984		$	14,356
CURRENT LIABILITIES
Accounts payable	$	696		$	447
Accrued liabilities	182			253
Total current liabilities	878			700
LONG-TERM DEBT, NET	6,295			—
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred domestic and foreign income taxes	3,227			2,904
Other	531			509
	3,758			3,413
TOTAL LIABILITIES	$	10,931		$	4,113

Sales and other operating revenues and income from discontinued operations related to California Resources were as follows:

For the years ended December 31, (in millions)	2014		2013		2012
Sales and other operating revenue from discontinued operations	$	3,951	$	4,285	$	4,072
Income from discontinued operations before-tax	1,205		1,531		1,265
Income tax expense	440		541		459
Income from discontinued operations	$	765	$	990	$	806

76

2014 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	$	3,602		$	3,703			$	3,586		$	2,996
Chemical	1,220			1,242				1,232			1,123
Midstream, marketing and other	340			440				261			332
Eliminations	(194		)	(252		)		(175		)	(144		)
Net sales	$	4,968		$	5,133			$	4,904		$	4,307
Gross profit	$	2,197		$	2,274			$	1,977		$	1,254
Segment earnings
Oil and gas	$	1,719		$	1,767		(a)	$	1,568		$	(4,626	)	(a)
Chemical	136			133				140			11			(b)
Midstream, marketing and other (c)	162			208				105			2,089			(d)
	2,017			2,108				1,813			(2,526		)
Unallocated corporate items
Interest expense, net	(20		)	(18		)		(15		)	(18		)
Income taxes	(794		)	(809		)		(699		)	617
Other	(68		)	(123		)		(104		)	(1,505		)	(e)
Income from continuing operations (c)	1,135			1,158				995			(3,432		)
Discontinued operations, net	255			273				213			19
Net income attributable to common stock	$	1,390		$	1,431			$	1,208		(3,413		)
Basic earnings per common share
Income from continuing operations	$	1.43		$	1.48			$	1.28		$	(4.44	)
Discontinued operations, net	0.32			0.35				0.27			0.03
Basic earnings per common share	$	1.75		$	1.83			$	1.55		$	(4.41	)
Diluted earnings per common share
Income from continuing operations	$	1.43		$	1.47			$	1.28		$	(4.44	)
Discontinued operations, net	0.32			0.35				0.27			0.03
Diluted earnings per common share	$	1.75		$	1.82			$	1.55		$	(4.41	)
Dividends per common share	$	0.72		$	0.72			$	0.72		$	0.72
Market price per common share
High	$	97.84		$	105.64			$	104.48		$	97.14
Low	$	85.90		$	93.27			$	95.70		$	72.32

(a) Includes second quarter pre-tax charges of $471 million related to the impairment of domestic non-producing acreage. Includes second quarter pre-tax gain of $531 million from sale of Hugoton Field. Includes fourth quarter pre-tax charges of $5.4 billion related to the impairment of oil and gas assets.

(b) Includes fourth quarter pre-tax charges of $149 million related to the impairment of chemical assets.

(c) Midstream, marketing and other segment earnings are net of non-controlling interest.

(d) Includes fourth quarter pre-tax gains of $633 million from the sale of BridgeTex Pipeline and $1,351 million for the sale of a portion of an investment in Plains Pipeline.

(e) Includes fourth quarter pre-tax charges of $805 million related to the impairment of Joslyn asset and an other than temporary loss of $553 million for available for sale investment in California Resources stock.

77

2013 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	$	3,431		$	3,707			$	3,961		$	3,909
Chemical	1,175			1,187				1,200			1,111
Midstream, marketing and other	381			196				357			240
Eliminations	(162		)	(179		)		(176		)	(168		)
Net sales	$	4,825		$	4,911			$	5,342		$	5,092
Gross profit	$	2,099		$	2,139			$	2,532		$	2,142
Segment earnings
Oil and gas	$	1,542		$	1,751			$	1,973		$	1,145		(a)
Chemical	159			275			(b)	181			128
Midstream, marketing and other	208			35				189			1,091			(c)
	1,909			2,061				2,343			2,364
Unallocated corporate items
Interest expense, net	(34		)	(33		)		(32		)	(25		)
Income taxes	(708		)	(773		)		(891		)	(842		)
Other	(57		)	(162		)		(99		)	(89		)
Income from continuing operations	1,110			1,093				1,321			1,408
Discontinued operations, net	245			229				262			235
Net income	$	1,355		$	1,322			$	1,583		$	1,643
Basic earnings per common share
Income from continuing operations	$	1.38		$	1.36			$	1.64		$	1.75
Discontinued operations, net	0.30			0.28				0.32			0.29
Basic earnings per common share	$	1.68		$	1.64			$	1.96		$	2.04
Diluted earnings per common share
Income from continuing operations	$	1.38		$	1.36			$	1.63		$	1.75
Discontinued operations, net	0.30			0.28				0.33			0.29
Diluted earnings per common share	$	1.68		$	1.64			$	1.96		$	2.04
Dividends per common share	$	0.64		$	0.64			$	0.64		$	0.64
Market price per common share
High	$	88.74		$	95.57			$	94.50		$	99.42
Low	$	77.21		$	77.91			$	84.91		$	90.13

(a) Includes fourth quarter pre-tax charges of $607 million related to the impairment of domestic non-producing acreage.

(b) Includes second quarter pre-tax gain of $131 million from the sale of the Carbocloro investment.

(c) Includes fourth quarter pre-tax gain of $1,044 million from the sale of a portion of an investment in Plains Pipeline.

78

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. Proved oil, NGLs 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, NGLs 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 2014, 2013 and 2012 disclosures, the calculated average West Texas Intermediate oil prices were $94.99, $96.94 and $94.71 per barrel, respectively. The calculated average Henry Hub gas prices for 2014, 2013 and 2012 were $4.42, $3.65 and $2.79 per MMBtu, respectively. 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.

Lower crude oil, natural gas, NGLs and refined products prices may reduce the amount of these commodities that can be produced economically, which may reduce Occidental's revenues, operating income and cash flows. Recent global economic conditions have driven oil and gas prices down significantly. These conditions may continue for an extended period. Prolonged or further declines in commodity prices could require Occidental to further reduce capital spending, potentially impacting either the quantity or the development timing of proved undeveloped reserves.

All supplemental oil and gas information excludes California Resources for all periods presented.

79

Oil 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, 2011	1,019		96		386		1,501
Revisions of previous estimates	(25	)	4		(3	)	(24	)
Improved recovery	81		7		30		118
Extensions and discoveries	3		—		27		30
Purchases of proved reserves	52		—		—		52
Production	(61	)	(11	)	(67	)	(139	)
Balance at December 31, 2012	1,069		96		373		1,538
Revisions of previous estimates	(36	)	(5	)	12		(29	)
Improved recovery	137		7		60		204
Extensions and discoveries	4		—		14		18
Purchases of proved reserves	25		—		—		25
Sales of proved reserves	(4	)	—		—		(4	)
Production	(64	)	(10	)	(65	)	(139	)
Balance at December 31, 2013	1,131		88		394		1,613
Revisions of previous estimates	(54	)	6		40		(8	)
Improved recovery	224		9		32		265
Extensions and discoveries	15		—		2		17
Purchases of proved reserves	33		—		—		33
Sales of proved reserves	(9	)	—		—		(9	)
Production	(67	)	(11	)	(63	)	(141	)
Balance at December 31, 2014	1,273		92		405		1,770
PROVED DEVELOPED RESERVES
December 31, 2011	780		69		317		1,166
December 31, 2012	803		82		295		1,180
December 31, 2013	822		76		281		1,179
December 31, 2014  (b)	819		86		316		1,221
PROVED UNDEVELOPED RESERVES
December 31, 2011	239		27		69		335
December 31, 2012	266		14		78		358
December 31, 2013	309		12		113		434
December 31, 2014 (c)	454		6		89		549

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

(b) Approximately 15 percent of the proved developed reserves at December 31, 2014 are nonproducing, primarily associated with the Al Hosn gas project in the United Arab Emirates.

(c) A portion of the proved undeveloped reserves associated with the Al Hosn gas project is expected to be developed beyond five years and is tied to an approved long term development project.

80

NGLs Reserves
in millions of barrels (MMbbl)
	United		Latin	Middle East/
	States		America	North Africa		Total
PROVED DEVELOPED AND UNDEVELOPED RESERVES
Balance at December 31, 2011	158		—	55		213
Revisions of previous estimates	15		—	—		15
Improved recovery	3		—	—		3
Extensions and discoveries	—		—	64		64
Purchases of proved reserves	1		—	—		1
Production	(21	)	—	(3	)	(24	)
Balance at December 31, 2012	156		—	116		272
Revisions of previous estimates	53		—	(1	)	52
Improved recovery	9		—	—		9
Extensions and discoveries	—		—	22		22
Purchases of proved reserves	7		—	—		7
Production	(21	)	—	(3	)	(24	)
Balance at December 31, 2013	204		—	134		338
Revisions of previous estimates	6		—	8		14
Improved recovery	37		—	—		37
Extensions and discoveries	2		—	—		2
Purchases of proved reserves	3		—	—		3
Sales of proved reserves	(10	)	—	—		(10	)
Production	(20	)	—	(2	)	(22	)
Balance at December 31, 2014	222		—	140		362
PROVED DEVELOPED RESERVES
December 31, 2011	123		—	55		178
December 31, 2012	124		—	53		177
December 31, 2013	151		—	51		202
December 31, 2014 (a)	147		—	109		256
PROVED UNDEVELOPED RESERVES
December 31, 2011	35		—	—		35
December 31, 2012	32		—	63		95
December 31, 2013	53		—	83		136
December 31, 2014 (b)	75		—	31		106

(a) Approximately 31 percent of the proved developed reserves at December 31, 2014 are nonproducing, primarily associated with the Al Hosn gas project.

(b) A portion of the proved undeveloped reserves associated with the Al Hosn gas project is expected to be developed beyond five years and is tied to an approved long term development project.

81

Gas Reserves
in billions of cubic feet (Bcf)
	United		Latin		Middle East/
	States		America		North Africa (a)		Total
PROVED DEVELOPED AND UNDEVELOPED RESERVES
Balance at December 31, 2011	2,449		33		1,925		4,407
Revisions of previous estimates	(581	)	—		62		(519	)
Improved recovery	207		11		34		252
Extensions and discoveries	7		—		784		791
Purchases of proved reserves	80		—		—		80
Production	(207	)	(5	)	(165	)	(377	)
Balance at December 31, 2012	1,955		39		2,640		4,634
Revisions of previous estimates	(46	)	(11	)	(43	)	(100	)
Improved recovery	251		1		16		268
Extensions and discoveries	13		—		232		245
Purchases of proved reserves	34		—		—		34
Sales of proved reserves	(2	)	—		—		(2	)
Production	(193	)	(5	)	(158	)	(356	)
Balance at December 31, 2013	2,012		24		2,687		4,723
Revisions of previous estimates	(111	)	3		(273	)	(381	)
Improved recovery	284		4		25		313
Extensions and discoveries	27		—		101		128
Purchases of proved reserves	46		—		—		46
Sales of proved reserves	(371	)	—		—		(371	)
Production	(173	)	(4	)	(154	)	(331	)
Balance at December 31, 2014	1,714		27		2,386		4,127
PROVED DEVELOPED RESERVES
December 31, 2011	1,723		32		1,555		3,310
December 31, 2012	1,454		36		1,816		3,306
December 31, 2013	1,495		23		1,684		3,202
December 31, 2014 (b)	1,128		26		1,915		3,069
PROVED UNDEVELOPED RESERVES
December 31, 2011	726		1		370		1,097
December 31, 2012	501		3		824		1,328
December 31, 2013	517		1		1,003		1,521
December 31, 2014 (c)	586		1		471		1,058

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

(b) Approximately 26 percent of the proved developed reserves at December 31, 2014 are nonproducing, primarily associated with the Al Hosn gas project.

(c) A portion of the proved undeveloped reserves associated with the Al Hosn gas project is expected to be developed beyond five years and is tied to an approved long term development project.

82

Total Reserves
in millions of BOE (MMBOE) (a)
	United		Latin		Middle East/
	States		America		North Africa		Total (b)
PROVED DEVELOPED AND UNDEVELOPED RESERVES
Balance at December 31, 2011	1,585		101		762		2,448
Revisions of previous estimates	(107	)	4		7		(96	)
Improved recovery	119		9		36		164
Extensions and discoveries	4		—		222		226
Purchases of proved reserves	66		—		—		66
Production	(116	)	(12	)	(98	)	(226	)
Balance at December 31, 2012	1,551		102		929		2,582
Revisions of previous estimates	10		(7	)	4		7
Improved recovery	188		8		63		259
Extensions and discoveries	6		—		74		80
Purchases of proved reserves	37		—		—		37
Sales of proved reserves	(5	)	—		—		(5	)
Production	(117	)	(11	)	(94	)	(222	)
Balance at December 31, 2013	1,670		92		976		2,738
Revisions of previous estimates	(67	)	6		3		(58	)
Improved recovery	310		9		35		354
Extensions and discoveries	22		—		19		41
Purchases of proved reserves	43		—		—		43
Sales of proved reserves	(81	)	—		—		(81	)
Production	(116	)	(11	)	(91	)	(218	)
Balance at December 31, 2014	1,781		96		942		2,819
PROVED DEVELOPED RESERVES
December 31, 2011	1,190		74		631		1,895
December 31, 2012	1,169		88		651		1,908
December 31, 2013	1,222		80		613		1,915
December 31, 2014 (c)	1,154		90		744		1,988
PROVED UNDEVELOPED RESERVES
December 31, 2011	395		27		131		553
December 31, 2012	382		14		278		674
December 31, 2013	448		12		363		823
December 31, 2014 (d)	627		6		198		831

(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 for a number of years. For example, in 2014, the average prices of West Texas Intermediate (WTI) oil and New York Mercantile Exchange (NYMEX) natural gas were $93.00 per barrel and $4.34 per Mcf, respectively, resulting in an oil to gas ratio of over 20 to 1.

(b) Includes proved reserves related to production-sharing contracts (PSCs) and other similar economic arrangements of 0.7 billion BOE, 0.8 billion BOE, 0.8 billion BOE, and 1.0 billion BOE at December 31, 2014, 2013, 2012, and 2011, respectively.

(c) Approximately 20 percent of the proved developed reserves at December 31, 2014 are nonproducing, primarily associated with the Al Hosn gas project.

(d) A portion of the proved undeveloped reserves associated with the Al Hosn gas project is expected to be developed beyond five years and is tied to an approved long term development project.

,

83

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, 2014
Proved properties	$	33,186		$	2,788		$	19,545		$	55,519
Unproved properties	2,389			27			1,026			3,442
Total capitalized costs(a)	35,575			2,815			20,571			58,961
Proved properties depreciation, depletion and amortization	(13,943		)	(1,365		)	(12,625		)	(27,933		)
Unproved properties valuation	(1,301		)	(27		)	—			(1,328		)
Total Accumulated depreciation, depletion and amortization	(15,244		)	(1,392		)	(12,625		)	(29,261		)
Net capitalized costs	$	20,331		$	1,423		$	7,946		$	29,700
December 31, 2013
Proved properties	$	29,520		$	2,485		$	18,090		$	50,095
Unproved properties	2,509			27			190			2,726
Total capitalized costs(a)	32,029			2,512			18,280			52,821
Accumulated depreciation, depletion and amortization	(9,782		)	(1,175		)	(10,261		)	(21,218		)
Net capitalized costs	$	22,247		$	1,337		$	8,019		$	31,603
December 31, 2012
Proved properties	$	25,564		$	2,142		$	15,873		$	43,579
Unproved properties	3,654			27			220			3,901
Total capitalized costs(a)	29,218			2,169			16,093			47,480
Accumulated depreciation, depletion and amortization	(7,893		)	(1,068		)	(8,582		)	(17,543		)
Net capitalized costs	$	21,325		$	1,101		$	7,511		$	29,937

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

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, 2014
Property acquisition costs
Proved properties	$	771	$	—	$	—	$	771
Unproved properties	842		—		—		842
Exploration costs	379		4		180		563
Development costs	3,665		305		2,138		6,108
Costs incurred	$	5,657	$	309	$	2,318	$	8,284
FOR THE YEAR ENDED DECEMBER 31, 2013
Property acquisition costs
Proved properties	$	343	$	—	$	—	$	343
Unproved properties	151		—		—		151
Exploration costs	293		11		79		383
Development costs	2,659		329		2,117		5,105
Costs incurred	$	3,446	$	340	$	2,196	$	5,982
FOR THE YEAR ENDED DECEMBER 31, 2012
Property acquisition costs
Proved properties	$	1,333	$	—	$	14	$	1,347
Unproved properties	573		—		—		573
Exploration costs	379		1		114		494
Development costs	3,271		304		2,025		5,600
Costs incurred	$	5,556	$	305	$	2,153	$	8,014

84

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, 2014
Revenues (a)	$	6,773		$	977		$	6,160	$	13,910
Production costs (b)	1,683			185			1,076		2,944
Other operating expenses	588			(2		)	266		852
Depreciation, depletion and amortization	2,114			161			1,426		3,701
Taxes other than on income	519			15			—		534
Exploration expenses	70			4			76		150
Pretax income before impairments and related items	1,799			614			3,316		5,729
Asset impairments and related items	4,766			57			1,009		5,832
Pretax income (loss)	(2,967		)	557			2,307		(103		)
Income tax expense (c)	(1,182		)	223			1,730		771
Results of operations	$	(1,785	)	$	334		$	577	$	(874	)
FOR THE YEAR ENDED DECEMBER 31, 2013
Revenues (a)	$	7,028		$	1,075		$	6,949	$	15,052
Production costs (b)	1,457			158			1,172		2,787
Other operating expenses	582			21			278		881
Depreciation, depletion and amortization	1,890			107			1,679		3,676
Taxes other than on income	529			21			—		550
Exploration expenses	68			6			66		140
Pretax income before impairments and related items	2,502			762			3,754		7,018
Asset impairments and related items	607			—			—		607
Pretax income	1,895			762			3,754		6,411
Income tax expense (c)	591			256			1,805		2,652
Results of operations	$	1,304		$	506		$	1,949	$	3,759
FOR THE YEAR ENDED DECEMBER 31, 2012
Revenues (a)	$	6,426		$	1,085		$	7,486	$	14,997
Production costs (b)	1,710			165			1,061		2,936
Other operating expenses	498			43			224		765
Depreciation, depletion and amortization	1,544			117			1,404		3,065
Taxes other than on income	481			23			—		504
Exploration expenses	82			3			112		197
Pretax income before impairments and related items	2,111			734			4,685		7,530
Asset impairments and related items	1,690			—			—		1,690
Pretax income	421			734			4,685		5,840
Income tax expense (c)	70			252			2,159		2,481
Results of operations	$	351		$	482		$	2,526	$	3,359

(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.

85

RESULTS PER UNIT OF PRODUCTION FOR CONTINUING OPERATIONS

	United			Latin			Middle East/
$/BOE (a)	States			America			North Africa		Total
FOR THE YEAR ENDED DECEMBER 31, 2014
Revenues (b)	$	58.50		$	85.81		$	67.74	$	63.78
Production costs	14.54			16.25			11.83		13.50
Other operating expenses	5.08			(0.18		)	2.93		3.91
Depreciation, depletion and amortization	18.26			14.14			15.68		16.97
Taxes other than on income	4.48			1.32			—		2.45
Exploration expenses	0.60			0.35			0.84		0.69
Pretax income before impairments and related items	15.54			53.93			36.46		26.26
Asset impairments and related items	41.17			5.01			11.10		26.74
Pretax income (loss)	(25.63		)	48.92			25.36		(0.48		)
Income tax expense (c)	(10.21		)	19.59			19.02		3.54
Results of operations	$	(15.42	)	$	29.33		$	6.34	$	(4.02	)
FOR THE YEAR ENDED DECEMBER 31, 2013
Revenues (b)	$	60.17		$	100.46		$	73.68	$	67.86
Production costs	12.47			14.76			12.43		12.56
Other operating expenses	4.98			1.96			2.95		3.97
Depreciation, depletion and amortization	16.18			10.00			17.80		16.57
Taxes other than on income	4.53			1.96			—		2.48
Exploration expenses	0.58			0.56			0.70		0.63
Pretax income before impairments and related items	21.43			71.22			39.80		31.65
Asset impairments and related items	5.20			—			—		2.74
Pretax income	16.23			71.22			39.80		28.91
Income tax expense (c)	5.06			23.92			19.14		11.96
Results of operations	$	11.17		$	47.30		$	20.66	$	16.95
FOR THE YEAR ENDED DECEMBER 31, 2012
Revenues (b)	$	55.40		$	96.30		$	76.22	$	66.51
Production costs	14.74			14.64			10.80		13.02
Other operating expenses	4.29			3.82			2.28		3.39
Depreciation, depletion and amortization	13.31			10.38			14.30		13.59
Taxes other than on income	4.15			2.04			—		2.24
Exploration expenses	0.71			0.27			1.14		0.87
Pretax income before impairments and related items	18.20			65.15			47.70		33.40
Asset impairments and related items	14.57			—			—		7.50
Pretax income	3.63			65.15			47.70		25.90
Income tax expense (c)	0.60			22.37			21.98		11.00
Results of operations	$	3.03		$	42.78		$	25.72	$	14.90

(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 for a number of years. For example, in 2014, the average prices of WTI oil and NYMEX natural gas were $93.00 per barrel and $4.34 per Mcf, respectively, resulting in an oil to gas ratio of over 20 to 1.

(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.

86

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, 2014, 2013 and 2012, 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 to develop and produce proved reserves at year end. 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, 2014, 2013 and 2012. Such assumptions, which are required by regulation, have not always proven accurate in the past. Other valid assumptions would give rise to substantially different results.

Standardized Measure of Discounted Future Net Cash Flows
in millions
	United			Latin			Middle East/
	States			America			North Africa			Total
AT DECEMBER 31, 2014
Future cash inflows	$	122,377		$	8,325		$	48,684		$	179,386
Future costs
Production costs and other operating expenses	(48,436		)	(3,422		)	(13,020		)	(64,878		)
Development costs (a)	(16,618		)	(397		)	(7,245		)	(24,260		)
Future income tax expense	(15,939		)	(1,322		)	(11,211		)	(28,472		)
Future net cash flows	41,384			3,184			17,208			61,776
Ten percent discount factor	(23,722		)	(1,219		)	(6,686		)	(31,627		)
Standardized measure of discounted future net cash flows	$	17,662		$	1,965		$	10,522		$	30,149
AT DECEMBER 31, 2013
Future cash inflows	$	114,081		$	9,076		$	50,517		$	173,674
Future costs
Production costs and other operating expenses	(43,569		)	(3,375		)	(13,043		)	(59,987		)
Development costs (a)	(12,038		)	(477		)	(7,084		)	(19,599		)
Future income tax expense	(16,689		)	(1,571		)	(13,182		)	(31,442		)
Future net cash flows	41,785			3,653			17,208			62,646
Ten percent discount factor	(24,080		)	(1,557		)	(6,597		)	(32,234		)
Standardized measure of discounted future net cash flows	$	17,705		$	2,096		$	10,611		$	30,412
AT DECEMBER 31, 2012
Future cash inflows	$	104,353		$	10,574		$	48,914		$	163,841
Future costs
Production costs and other operating expenses	(41,812		)	(3,562		)	(11,922		)	(57,296		)
Development costs (a)	(9,929		)	(541		)	(5,539		)	(16,009		)
Future income tax expense	(14,199		)	(2,023		)	(14,165		)	(30,387		)
Future net cash flows	38,413			4,448			17,288			60,149
Ten percent discount factor	(21,998		)	(1,812		)	(6,656		)	(30,466		)
Standardized measure of discounted future net cash flows	$	16,415		$	2,636		$	10,632		$	29,683

(a) Includes asset retirement costs.

87

Changes in the Standardized Measure of Discounted Future
Net Cash Flows From Proved Reserve Quantities
in millions
For the years ended December 31,	2014			2013			2012
Beginning of year	$	30,412		$	29,683		$	31,313
Sales and transfers of oil and gas produced, net of production costs and other operating expenses	(11,016		)	(12,324		)	(12,124		)
Net change in prices received per barrel, net of production costs and other operating expenses	(3,641		)	2,000			(1,590		)
Extensions, discoveries and improved recovery, net of future production and development costs	4,754			4,792			3,728
Change in estimated future development costs	(3,375		)	(3,546		)	(4,769		)
Revisions of quantity estimates	190			(475		)	(653		)
Previously estimated development costs incurred during the period	4,676			2,926			3,143
Accretion of discount	3,456			3,325			3,692
Net change in income taxes	3,673			2,183			4,152
Purchases and sales of reserves in place, net	45			518			856
Changes in production rates and other	975			1,330			1,935
Net change	(263		)	729			(1,630		)
End of year	$	30,149		$	30,412		$	29,683

Average Sales Prices

The following table sets forth, for each of the three years in the period ended December 31, 2014, Occidental’s approximate average sales prices in continuing operations.

			United		Latin		Middle East/
			States		America		North Africa		Total
2014
Oil	—	Average sales price ($/bbl)	$	84.73	$	88.00	$	96.34	$	90.13
NGLs	—	Average sales price ($/bbl)	$	37.79	$	—	$	30.98	$	37.01
Gas	—	Average sales price ($/mcf)	$	3.97	$	8.94	$	0.77	$	2.55
2013
Oil	—	Average sales price ($/bbl)	$	92.48	$	103.21	$	104.48	$	98.81
NGLs	—	Average sales price ($/bbl)	$	38.65	$	—	$	33.00	$	38.00
Gas	—	Average sales price ($/mcf)	$	3.22	$	11.17	$	0.76	$	2.23
2012
Oil	—	Average sales price ($/bbl)	$	88.25	$	98.35	$	108.76	$	98.90
NGLs	—	Average sales price ($/bbl)	$	44.06	$	—	$	37.74	$	43.21
Gas	—	Average sales price ($/mcf)	$	2.48	$	11.85	$	0.76	$	1.85

88

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, 2014, Occidental’s net productive and dry–exploratory and development wells completed.

			United	Latin	Middle East/
			States	America	North Africa	Total
2014
Oil	—	Exploratory	25.3	—	5.2	30.5
		Development	419.4	51.5	253.2	724.1
Gas	—	Exploratory	1.6	—	2.3	3.9
		Development	32.5	1.0	12.6	46.1
Dry	—	Exploratory	—	0.8	3.0	3.8
		Development	—	0.5	—	0.5
2013
Oil	—	Exploratory	25.2	0.8	3.9	29.9
		Development	557.5	64.0	234.6	856.1
Gas	—	Exploratory	1.0	—	0.7	1.7
		Development	50.6	2.5	10.4	63.5
Dry	—	Exploratory	5.0	0.8	2.6	8.4
		Development	26.5	1.8	0.5	28.8
2012
Oil	—	Exploratory	31.0	—	3.3	34.3
		Development	535.3	51.8	264.6	851.7
Gas	—	Exploratory	2.9	—	—	2.9
		Development	129.0	1.0	6.5	136.5
Dry	—	Exploratory	5.5	—	6.1	11.6
		Development	27.5	0.4	2.4	30.3

Productive Oil and Gas Wells

The following table sets forth, as of December 31, 2014, Occidental’s productive oil and gas wells (both producing and capable of production).

Wells at December 31, 2014 (a)			United States			Latin America		Middle East/ North Africa			Total
Oil	—	Gross (b)	16,794	(837	)	1,446	—	3,856	(854	)	22,096	(1,691	)
		Net (c)	14,518	(772	)	722	—	2,031	(411	)	17,271	(1,183	)
Gas	—	Gross (b)	4,272	(216	)	34	—	174	(1	)	4,480	(217	)
		Net (c)	3,776	(196	)	32	—	87	(1	)	3,895	(197	)

(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.

89

Participation in Exploratory and Development Wells Being Drilled

The following table sets forth, as of December 31, 2014, Occidental’s participation in exploratory and development wells being drilled.

Wells at December 31, 2014			United States	Latin America	Middle East/ North Africa	Total
Exploratory and development wells
	—	Gross	158	11	41	210
	—	Net	147	6	20	173

At December 31, 2014, Occidental was participating in 124 pressure-maintenance projects, mostly waterfloods, in the United States, 12 in Latin America and 60 in the Middle East/North Africa.

Oil and Gas Acreage

The following table sets forth, as of December 31, 2014, Occidental’s holdings of developed and undeveloped oil and gas acreage.

Thousands of acres at			United	Latin	Middle East/
December 31, 2014			States	America	North Africa	Total
Developed (a)
	—	Gross (b)	7,146	130	1,409	8,685
	—	Net (c)	3,278	88	643	4,009
Undeveloped (d)
	—	Gross (b)	3,652	367	6,016	10,035
	—	Net (c)	1,230	247	4,152	5,629

(a) Acres spaced or assigned to productive wells.

(b) Total acres in which interests are held.

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

(d) Acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas, regardless of whether the acreage contains proved reserves.

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.

90

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, 2014. 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	2014	2013	2012
United States
Oil (MBBL)
Permian Resources	43	35	36
Permian EOR	111	111	106
Midcontinent and Other	27	24	20
Total excluding Hugoton	181	170	162
Hugoton	2	6	5
TOTAL	183	176	167
NGLs (MBBL)
Permian Resources	12	10	11
Permian EOR	30	29	28
Midcontinent and Other	12	15	14
Total excluding Hugoton	54	54	53
Hugoton	1	3	3
TOTAL	55	57	56
Natural gas (MMCF)
Permian Resources	120	117	114
Permian EOR	38	40	41
Midcontinent and Other	301	315	347
Total excluding Hugoton	459	472	502
Hugoton	17	56	63
TOTAL	476	528	565
Latin America
Oil (MBBL) - Colombia	27	29	29
Natural gas (MMCF) - Bolivia	11	12	13
Middle East/North Africa
Oil (MBBL)
Dolphin	7	6	8
Oman	69	66	67
Qatar	69	68	71
Other	28	39	40
TOTAL	173	179	186
NGLs (MBBL)
Dolphin	7	7	8
Other	—	—	1
TOTAL	7	7	9
Natural gas (MMCF)
Dolphin	143	142	163
Oman	43	51	57
Other	236	241	232
TOTAL	422	434	452
Total Production excluding Hugoton	591	591	599
Hugoton	6	18	19
Total Production (MBOE) (a)	597	609	618
(See footnotes following the Sales Volumes per Day table)

91

Sales Volumes per Day	2014	2013	2012
United States
Oil (MBBL)	183	176	167
NGLs (MBBL)	55	57	56
Natural gas (MMCF)	476	528	565
Latin America
Oil (MBBL) - Colombia	29	27	28
Natural gas (MMCF) - Bolivia	11	12	13
Middle East/North Africa
Oil (MBBL)
Dolphin	7	6	8
Oman	69	68	66
Qatar	69	67	71
Other	27	38	40
TOTAL	172	179	185
NGLs (MBBL)
Dolphin	7	7	8
Other	—	—	1
TOTAL	7	7	9
Natural gas (MMCF)	422	434	452
Total Sales excluding Hugoton	592	590	598
Hugoton	6	18	19
Total Sales Volumes (MBOE) (a)	598	608	617

(a) 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 for a number of years. For example, in 2014, the average prices of WTI oil and NYMEX natural gas were $93.00 per barrel and $4.34, respectively, resulting in an oil to gas ratio of over 20 to 1.

92

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
2014
Allowance for doubtful accounts	$	17	$	4	$	(2	)	$	—		$	19
Environmental	$	330	$	79	$	(7	)	$	(68	)	$	334
Litigation, tax and other reserves	166		1		190			(19		)	338
	$	496	$	80	$	183		$	(87	)	$	672	(b)
2013
Allowance for doubtful accounts	$	16	$	1	$	—		$	—		$	17
Environmental	$	344	$	60	$	—		$	(74	)	$	330
Litigation, tax and other reserves	229		3		4			(70		)	166
	$	573	$	63	$	4		$	(144	)	$	496	(b)
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)

Note:  The amounts presented represent continuing operations.

(a) Primarily represents payments.

(b) Of these amounts, $287 million, $101 million and $98 million in 2014, 2013 and 2012, respectively, are classified as current.

93

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

Occidental had no changes in, and no disagreements with, Occidental's accountants on accounting and financial disclosure.

ITEM 9A CONTROLS AND PROCEDURES

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

The management of Occidental Petroleum Corporation and its 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, 2014, based on the criteria for effective internal control over financial reporting described in Internal Control — Integrated Framework issued in 2013 by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this assessment, management believes that, as of December 31, 2014, 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.

DISCLOSURE CONTROLS AND PROCEDURES

Occidental's President and Chief Executive Officer and its Senior 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 Senior Vice President and Chief Financial Officer concluded that Occidental's disclosure controls and procedures were effective as of December 31, 2014.

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 2014 that has materially affected, or is reasonably likely to materially affect, Occidental's internal control over financial reporting. The Report of Independent Registered Public Accounting Firm on Internal Control over Financial Reporting is set forth in Item 8.

ITEM 9B OTHER INFORMATION

None.

94

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; Senior 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.

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. The information required by this Item 10 is incorporated herein by reference from Occidental’s definitive Proxy Statement, relating to its May 1, 2015 Annual Meeting of Stockholders, to be filed with the SEC pursuant to Regulation 14A within 120 days of December 31, 2014.

ITEM 11 EXECUTIVE COMPENSATION

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. The information required by this Item 11 is incorporated herein by reference from Occidental’s definitive Proxy Statement, relating to its May 1, 2015 Annual Meeting of Stockholders, to be filed with the SEC pursuant to Regulation 14A within 120 days of December 31, 2014.

ITEM 12 SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The information required by this Item 12 is incorporated herein by reference from Occidental’s definitive Proxy Statement, relating to its May 1, 2015 Annual Meeting of Stockholders, to be filed with the SEC pursuant to Regulation 14A within 120 days of December 31, 2014.

ITEM 13 CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

The information required by this Item 13 is incorporated herein by reference from Occidental’s definitive Proxy Statement, relating to its May 1, 2015 Annual Meeting of Stockholders, to be filed with the SEC pursuant to Regulation 14A within 120 days of December 31, 2014.

ITEM 14 PRINCIPAL ACCOUNTING FEES AND SERVICES

The information required by this Item 14 is incorporated herein by reference from Occidental’s definitive Proxy Statement, relating to its May 1, 2015 Annual Meeting of Stockholders, to be filed with the SEC pursuant to Regulation 14A within 120 days of December 31, 2014.

95

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

2.1*	Separation and Distribution Agreement by and between Occidental Petroleum Corporation and California Resources Corporation, dated November 25, 2014 (filed as Exhibit 2.1 to the Current Report on Form 8-K of Occidental dated November 25, 2014 (date of earliest event reported), filed December 1, 2014, File No. 1-9210).
3.(i)*	Restated Certificate of Incorporation of Occidental, dated November 12, 1999 (filed as Exhibit 3.(i) to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 1999, File No. 1-9210).
3.(i)(a)*	Certificate of Change of Location of Registered Office and of Registered Agent, dated July 6, 2001 (filed as Exhibit 3.1(i) to the Registration Statement on Form S-3 of Occidental, File No. 333-82246).
3.(i)(b)*	Certificate of Amendment of Restated Certificate of Incorporation of Occidental Petroleum Corporation, dated May 5, 2006 (filed as Exhibit 3.(i)(b) to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2006, File No. 1-9210).
3.(i)(c)*	Certificate of Amendment of Restated Certificate of Incorporation of Occidental Petroleum Corporation, dated May 1, 2009 (filed as Exhibit 3.(i)(c) to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended June 30, 2009, File No. 1-9210).
3.(ii)*	Bylaws of Occidental, as amended through October 2, 2014 (filed as Exhibit 3.(ii) to the Current Report on Form 8-K of Occidental dated October 1, 2014 (date of earliest event reported), filed October 7, 2014, 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 10.73 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*	Settlement Agreement and General Release, dated December 20, 2013, between Occidental and Dr. Ray R. Irani (filed as Exhibit 99.1 to the Current Report on Form 8-K of Occidental dated December 20, 2013 (date of earliest event reported), filed December 23, 2013, 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*	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).
10.4*	Retention Payment and Separation Benefits Attachment (filed as Exhibit 10.6 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2012, File No. 1-9210).
10.5*	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).
10.6*	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).
10.7*	Occidental Petroleum Insured Medical Plan, as amended and restated effective April 29, 1994, amending and restating the Occidental Petroleum Corporation Executive Medical Plan (as amended and restated effective April 1, 1993) (filed as Exhibit 10 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ending March 31, 1994, File No. 1-9210).

____________________________

* Incorporated herein by reference

96

10.8*	Form of Occidental Petroleum Corporation Modified Deferred Compensation Plan (Effective December 31, 2006, Amended and Restated Effective November 1, 2008) (filed as Exhibit 10.4 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended September 30, 2008, File No. 1-9210).
10.9*	Form of Occidental Petroleum Corporation Amendment to Senior Executive Supplemental Life Insurance Plan (Effective as of January 1, 1986, Amended and Restated Effective as of January 1, 1996) (filed as Exhibit 10.5 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended September 30, 2008, File No. 1-9210).
10.10*	Form of Occidental Petroleum Corporation Amendment to Senior Executive Survivor Benefit Plan (Effective as of January 1, 1986, Amended and Restated Effective as of January 1, 1996) (filed as Exhibit 10.6 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended September 30, 2008, File No. 1-9210).
10.11*	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).
10.12*	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).
10.13*	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).
10.14*	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).
10.15*	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).
10.16*	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) (filed as Exhibit 10.19 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2012, File No. 1-9210).
10.17*	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).
10.18*	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).
10.19*	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).
10.20*	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).
10.21*	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).
10.22*	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).
10.23*	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).
10.24*	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).
10.25*	Form of Occidental Petroleum Corporation 2005 Deferred Stock Program (Restatement Effective as of November 1, 2008) (filed as Exhibit 10.8 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended September 30, 2008, File No. 1-9210).
10.26*	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).
10.27*	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).
10.28*	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).
10.29*	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).
10.30*	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).
10.31*	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).
10.32*	Director Retainer and Attendance Fees (filed as Exhibit 10.36 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2013, File No. 1-9210).

____________________________

* Incorporated herein by reference

97

10.33*	Description of Automatic Grant of Directors’ Restricted Stock Awards Pursuant to the Terms of the Occidental Petroleum Corporation 2005 Long-Term Incentive Plan (filed as Exhibit 10.37 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2013, File No. 1-9210).
10.34*	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).
10.35*	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).
10.36*	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).
10.37*	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).
10.38*	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).
10.39*	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).
10.40*	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).
10.41*	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).
10.42*	Form of Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Total Shareholder Return Incentive Award Terms and Conditions (Equity-based, Equity and Cash-settled Award) (filed as Exhibit 10.2 to the Current Report on Form 8-K of Occidental dated July 13, 2011 (date of earliest event reported), filed July 18, 2011, File No. 1-9210).
10.43*	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).
10.44*	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).
10.45*	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).
10.46*	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).
10.47*	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).
10.48*	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).
10.49*	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).
10.50*	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).
10.51*	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).
10.52*	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).
10.53*	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).
10.54*	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).
10.55*	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).

____________________________

* Incorporated herein by reference

98

10.56*	Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Restricted Stock Incentive Award Terms and Conditions (filed as Exhibit 10.1 to the Current Report on Form 8-K of Occidental dated July 10, 2013 (date of earliest event reported), filed July 16, 2013, File No. 1-9210).
10.57*	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 10.1 to the Current Report on Form 8-K of Occidental dated July 22, 2013 (date of earliest event reported), filed July 26, 2013, File No. 1-9210).
10.58*	Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Restricted Stock Incentive Award Terms and Conditions (Performance-Based) (filed as Exhibit 10.2 to the Current Report on Form 8-K of Occidental dated July 22, 2013 (date of earliest event reported), filed July 26, 2013, File No. 1-9210).
10.59*	Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Return on Capital Employed Incentive Award Terms and Conditions (Equity-Based, Equity-Settled Award) (filed as Exhibit 10.3 to the Current Report on Form 8-K of Occidental dated July 22, 2013 (date of earliest event reported), filed July 26, 2013, File No. 1-9210).
10.60*	Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Occidental Oil and Gas Corporation Return on Assets Incentive Award Terms and Conditions (Equity-Based, Equity-Settled Award) (filed as Exhibit 10.4 to the Current Report on Form 8-K of Occidental dated July 22, 2013 (date of earliest event reported), filed July 26, 2013, File No. 1-9210).
10.61*	Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Occidental Oil and Gas Corporation Return on Assets Incentive Award Terms and Conditions (Equity-Based, Equity-Settled Award) (Americas) (filed as Exhibit 10.5 to the Current Report on Form 8-K of Occidental dated July 22, 2013 (date of earliest event reported), filed July 26, 2013, File No. 1-9210).
10.62*	Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Occidental Oil and Gas Corporation Return on Assets Incentive Award Terms and Conditions (Equity-Based, Equity-Settled Award) (MENA) (filed as Exhibit 10.6 to the Current Report on Form 8-K of Occidental dated July 22, 2013 (date of earliest event reported), filed July 26, 2013, File No. 1-9210).
10.63*	Occidental Petroleum Corporation Acknowledgement Letter dated April 29, 2013 (filed as Exhibit 10.8 to the Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2013, File No. 1-9210).
10.64*	Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Restricted Stock Incentive Award Terms and Conditions (filed as Exhibit 10.9 to the Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2013, File No. 1-9210).
10.65*	Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Return on Capital Employed Incentive Award Terms and Conditions (Cash-Based, Cash-Settled Award) (filed as Exhibit 10.10 to the Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2013, File No. 1-9210).
10.66*	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 10.11 to the Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2013, File No. 1-9210).
10.67*	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 10.12 to the Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2013, File No. 1-9210).
10.68*	Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Occidental Oil and Gas Corporation Return on Assets Incentive Award Terms And Conditions (Cash-Based, Cash-Settled Award) (Americas) (filed as Exhibit 10.13 to the Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2013, File No. 1-9210).
10.69*	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) (MENA) (filed as Exhibit 10.14 to the Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2013, File No. 1-9210).
10.70*	Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Occidental Chemical Corporation Return on Assets Incentive Award Terms and Conditions (Equity-Based, Equity-Settled Award) (filed as Exhibit 10.15 to the Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2013, File No. 1-9210).
10.71*	Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Common Stock Unit Award For Non-Employee Directors Grant Agreement (filed as Exhibit 10.1 to the Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2014, File No. 1-9210).
10.72*	Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Common Stock Award For Non-Employee Directors Grant Agreement (filed as Exhibit 10.2 to the Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2014, File No. 1-9210).
10.73	Form of Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Nonstatutory Stock Option Award Terms and Conditions.
10.74*	Stockholder’s and Registration Rights Agreement by and between Occidental Petroleum Corporation and California Resources Corporation, dated November 25, 2014 (filed as Exhibit 10.1 to the Current Report on Form 8-K of Occidental dated November 25, 2014 (date of earliest event reported), filed December 1, 2014, File No. 1-9210).
10.75*	Tax Sharing Agreement by and between Occidental Petroleum Corporation and California Resources Corporation, dated November 25, 2014 (filed as Exhibit 10.2 to the Current Report on Form 8-K of Occidental dated November 25, 2014 (date of earliest event reported), filed December 1, 2014, File No. 1-9210).
10.76*	Employee Matters Agreement by and between Occidental Petroleum Corporation and California Resources Corporation, dated November 25, 2014 (filed as Exhibit 10.3 to the Current Report on Form 8-K of Occidental dated November 25, 2014 (date of earliest event reported), filed December 1, 2014, File No. 1-9210).
10.77*	Transition Services Agreement by and between Occidental Petroleum Corporation and California Resources Corporation, dated November 25, 2014 (filed as Exhibit 10.4 to the Current Report on Form 8-K of Occidental dated November 25, 2014 (date of earliest event reported), filed December 1, 2014, File No. 1-9210).
10.78*	Area of Mutual Interest Agreement by and between Occidental Petroleum Corporation and California Resources Corporation, dated November 25, 2014 (filed as Exhibit 10.5 to the Current Report on Form 8-K of Occidental dated November 25, 2014 (date of earliest event reported), filed December 1, 2014, File No. 1-9210).
10.79*	Confidentiality and Trade Secret Protection Agreement by and between Occidental Petroleum Corporation and California Resources Corporation, dated November 25, 2014 (filed as Exhibit 10.6 to the Current Report on Form 8-K of Occidental dated November 25, 2014 (date of earliest event reported), filed December 1, 2014, File No. 1-9210).

____________________________

* Incorporated herein by reference

99

10.80*	Intellectual Property License Agreement by and between Occidental Petroleum Corporation and California Resources Corporation, dated November 25, 2014 (filed as Exhibit 10.7 to the Current Report on Form 8-K of Occidental dated November 25, 2014 (date of earliest event reported), filed December 1, 2014, 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, 2014.
21	List of subsidiaries of Occidental at December 31, 2014.
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 Proved 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, 2014.
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

100

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

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

	Title	Date
/s/ Stephen I. Chazen	President,	February 23, 2015
Stephen I. Chazen	Chief Executive Officer and Director
/s/ Christopher G. Stavros	Senior Vice President and	February 23, 2015
Christopher G. Stavros	Chief Financial Officer
/s/ Jennifer M. Kirk	Vice President, Controller and	February 23, 2015
Jennifer M. Kirk	Principal Accounting Officer
/s/ Spencer Abraham	Director	February 23, 2015
Spencer Abraham
/s/ Howard I. Atkins	Director	February 23, 2015
Howard I. Atkins
/s/ Eugene L. Batchelder	Director	February 23, 2015
Eugene L. Batchelder
/s/ Edward P. Djerejian	Chairman of the Board of Directors	February 23, 2015
Edward P. Djerejian
/s/ John E. Feick	Director	February 23, 2015
John E. Feick
/s/ Margaret M. Foran	Director	February 23, 2015
Margaret M. Foran
/s/ Carlos M. Gutierrez	Director	February 23, 2015
Carlos M. Gutierrez

101

	Title	Date
/s/ William R. Klesse	Director	February 23, 2015
William R. Klesse
/s/ Avedick B. Poladian	Director	February 23, 2015
Avedick B. Poladian
/s/ Elisse B. Walter	Director	February 23, 2015
Elisse B. Walter

© 2015 Occidental Petroleum Corporation

102

EXHIBIT INDEX
EXHIBITS
2.1*	Separation and Distribution Agreement by and between Occidental Petroleum Corporation and California Resources Corporation, dated November 25, 2014 (filed as Exhibit 2.1 to the Current Report on Form 8-K of Occidental dated November 25, 2014 (date of earliest event reported), filed December 1, 2014, File No. 1-9210).
3.(i)*	Restated Certificate of Incorporation of Occidental, dated November 12, 1999 (filed as Exhibit 3.(i) to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 1999, File No. 1-9210).
3.(i)(a)*	Certificate of Change of Location of Registered Office and of Registered Agent, dated July 6, 2001 (filed as Exhibit 3.1(i) to the Registration Statement on Form S-3 of Occidental, File No. 333-82246).
3.(i)(b)*	Certificate of Amendment of Restated Certificate of Incorporation of Occidental Petroleum Corporation, dated May 5, 2006 (filed as Exhibit 3.(i)(b) to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2006, File No. 1-9210).
3.(i)(c)*	Certificate of Amendment of Restated Certificate of Incorporation of Occidental Petroleum Corporation, dated May 1, 2009 (filed as Exhibit 3.(i)(c) to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended June 30, 2009, File No. 1-9210).
3.(ii)*	Bylaws of Occidental, as amended through October 2, 2014 (filed as Exhibit 3.(ii) to the Current Report on Form 8-K of Occidental dated October 1, 2014 (date of earliest event reported), filed October 7, 2014, 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 10.73 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*	Settlement Agreement and General Release, dated December 20, 2013, between Occidental and Dr. Ray R. Irani (filed as Exhibit 99.1 to the Current Report on Form 8-K of Occidental dated December 20, 2013 (date of earliest event reported), filed December 23, 2013, 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*	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).
10.4*	Retention Payment and Separation Benefits Attachment (filed as Exhibit 10.6 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2012, File No. 1-9210).
10.5*	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).
10.6*	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).
10.7*	Occidental Petroleum Insured Medical Plan, as amended and restated effective April 29, 1994, amending and restating the Occidental Petroleum Corporation Executive Medical Plan (as amended and restated effective April 1, 1993) (filed as Exhibit 10 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ending March 31, 1994, File No. 1-9210).
10.8*	Form of Occidental Petroleum Corporation Modified Deferred Compensation Plan (Effective December 31, 2006, Amended and Restated Effective November 1, 2008) (filed as Exhibit 10.4 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended September 30, 2008, File No. 1-9210).
10.9*	Form of Occidental Petroleum Corporation Amendment to Senior Executive Supplemental Life Insurance Plan (Effective as of January 1, 1986, Amended and Restated Effective as of January 1, 1996) (filed as Exhibit 10.5 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended September 30, 2008, File No. 1-9210).
10.10*	Form of Occidental Petroleum Corporation Amendment to Senior Executive Survivor Benefit Plan (Effective as of January 1, 1986, Amended and Restated Effective as of January 1, 1996) (filed as Exhibit 10.6 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended September 30, 2008, File No. 1-9210).
10.11*	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).
10.12*	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).
10.13*	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).
10.14*	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).
10.15*	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).
10.16*	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) (filed as Exhibit 10.19 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2012, File No. 1-9210).

103

10.17*	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).
10.18*	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).
10.19*	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).
10.20*	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).
10.21*	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).
10.22*	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).
10.23*	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).
10.24*	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).
10.25*	Form of Occidental Petroleum Corporation 2005 Deferred Stock Program (Restatement Effective as of November 1, 2008) (filed as Exhibit 10.8 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended September 30, 2008, File No. 1-9210).
10.26*	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).
10.27*	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).
10.28*	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).
10.29*	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).
10.30*	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).
10.31*	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).
10.32*	Director Retainer and Attendance Fees (filed as Exhibit 10.36 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2013, File No. 1-9210).
10.33*	Description of Automatic Grant of Directors’ Restricted Stock Awards Pursuant to the Terms of the Occidental Petroleum Corporation 2005 Long-Term Incentive Plan (filed as Exhibit 10.37 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2013, File No. 1-9210).
10.34*	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).
10.35*	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).
10.36*	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).
10.37*	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).
10.38*	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).
10.39*	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).
10.40*	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).
10.41*	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).
10.42*	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).

104

10.43*	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).
10.44*	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).
10.45*	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).
10.46*	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).
10.47*	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).
10.48*	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).
10.49*	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).
10.50*	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).
10.51*	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).
10.52*	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).
10.53*	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).
10.54*	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).
10.55*	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).
10.56*	Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Restricted Stock Incentive Award Terms and Conditions (filed as Exhibit 10.1 to the Current Report on Form 8-K of Occidental dated July 10, 2013 (date of earliest event reported), filed July 16, 2013, File No. 1-9210).
10.57*	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 10.1 to the Current Report on Form 8-K of Occidental dated July 22, 2013 (date of earliest event reported), filed July 26, 2013, File No. 1-9210).
10.58*	Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Restricted Stock Incentive Award Terms and Conditions (Performance-Based) (filed as Exhibit 10.2 to the Current Report on Form 8-K of Occidental dated July 22, 2013 (date of earliest event reported), filed July 26, 2013, File No. 1-9210).
10.59*	Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Return on Capital Employed Incentive Award Terms and Conditions (Equity-Based, Equity-Settled Award) (filed as Exhibit 10.3 to the Current Report on Form 8-K of Occidental dated July 22, 2013 (date of earliest event reported), filed July 26, 2013, File No. 1-9210).
10.60*	Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Occidental Oil and Gas Corporation Return on Assets Incentive Award Terms and Conditions (Equity-Based, Equity-Settled Award) (filed as Exhibit 10.4 to the Current Report on Form 8-K of Occidental dated July 22, 2013 (date of earliest event reported), filed July 26, 2013, File No. 1-9210).
10.61*	Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Occidental Oil and Gas Corporation Return on Assets Incentive Award Terms and Conditions (Equity-Based, Equity-Settled Award) (Americas) (filed as Exhibit 10.5 to the Current Report on Form 8-K of Occidental dated July 22, 2013 (date of earliest event reported), filed July 26, 2013, File No. 1-9210).
10.62*	Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Occidental Oil and Gas Corporation Return on Assets Incentive Award Terms and Conditions (Equity-Based, Equity-Settled Award) (MENA) (filed as Exhibit 10.6 to the Current Report on Form 8-K of Occidental dated July 22, 2013 (date of earliest event reported), filed July 26, 2013, File No. 1-9210).
10.63*	Occidental Petroleum Corporation Acknowledgement Letter dated April 29, 2013 (filed as Exhibit 10.8 to the Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2013, File No. 1-9210).
10.64*	Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Restricted Stock Incentive Award Terms and Conditions (filed as Exhibit 10.9 to the Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2013, File No. 1-9210).
10.65*	Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Return on Capital Employed Incentive Award Terms and Conditions (Cash-Based, Cash-Settled Award) (filed as Exhibit 10.10 to the Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2013, File No. 1-9210).
10.66*	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 10.11 to the Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2013, File No. 1-9210).
10.67*	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 10.12 to the Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2013, File No. 1-9210).

105

10.68*	Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Occidental Oil and Gas Corporation Return on Assets Incentive Award Terms And Conditions (Cash-Based, Cash-Settled Award) (Americas) (filed as Exhibit 10.13 to the Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2013, File No. 1-9210).
10.69*	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) (MENA) (filed as Exhibit 10.14 to the Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2013, File No. 1-9210).
10.70*	Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Occidental Chemical Corporation Return on Assets Incentive Award Terms and Conditions (Equity-Based, Equity-Settled Award) (filed as Exhibit 10.15 to the Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2013, File No. 1-9210).
10.71*	Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Common Stock Unit Award For Non-Employee Directors Grant Agreement (filed as Exhibit 10.1 to the Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2014, File No. 1-9210).
10.72*	Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Common Stock Award For Non-Employee Directors Grant Agreement (filed as Exhibit 10.2 to the Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2014, File No. 1-9210).
10.73	Form of Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Nonstatutory Stock Option Award Terms and Conditions.
10.74*	Stockholder’s and Registration Rights Agreement by and between Occidental Petroleum Corporation and California Resources Corporation, dated November 25, 2014 (filed as Exhibit 10.1 to the Current Report on Form 8-K of Occidental dated November 25, 2014 (date of earliest event reported), filed December 1, 2014, File No. 1-9210).
10.75*	Tax Sharing Agreement by and between Occidental Petroleum Corporation and California Resources Corporation, dated November 25, 2014 (filed as Exhibit 10.2 to the Current Report on Form 8-K of Occidental dated November 25, 2014 (date of earliest event reported), filed December 1, 2014, File No. 1-9210).
10.76*	Employee Matters Agreement by and between Occidental Petroleum Corporation and California Resources Corporation, dated November 25, 2014 (filed as Exhibit 10.3 to the Current Report on Form 8-K of Occidental dated November 25, 2014 (date of earliest event reported), filed December 1, 2014, File No. 1-9210).
10.77*	Transition Services Agreement by and between Occidental Petroleum Corporation and California Resources Corporation, dated November 25, 2014 (filed as Exhibit 10.4 to the Current Report on Form 8-K of Occidental dated November 25, 2014 (date of earliest event reported), filed December 1, 2014, File No. 1-9210).
10.78*	Area of Mutual Interest Agreement by and between Occidental Petroleum Corporation and California Resources Corporation, dated November 25, 2014 (filed as Exhibit 10.5 to the Current Report on Form 8-K of Occidental dated November 25, 2014 (date of earliest event reported), filed December 1, 2014, File No. 1-9210).
10.79*	Confidentiality and Trade Secret Protection Agreement by and between Occidental Petroleum Corporation and California Resources Corporation, dated November 25, 2014 (filed as Exhibit 10.6 to the Current Report on Form 8-K of Occidental dated November 25, 2014 (date of earliest event reported), filed December 1, 2014, File No. 1-9210).
10.80*	Intellectual Property License Agreement by and between Occidental Petroleum Corporation and California Resources Corporation, dated November 25, 2014 (filed as Exhibit 10.7 to the Current Report on Form 8-K of Occidental dated November 25, 2014 (date of earliest event reported), filed December 1, 2014, 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, 2014.
21	List of subsidiaries of Occidental at December 31, 2014.
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 Proved 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, 2014.
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.

106

EX-10.73

OCCIDENTAL PETROLEUM CORPORATION

2005 LONG-TERM INCENTIVE PLAN

NONSTATUTORY STOCK OPTION AWARD TERMS AND CONDITIONS

DATE OF GRANT: See Morgan Stanley Benefit Access “Stock Options and SARs /My Grants/Grant Date”

SHARES OF COMMON STOCK

SUBJECT TO THIS OPTION: See Morgan Stanley Benefit Access “Stock Options and SARs /My Grants/Granted”

VESTING AND EXERCISE

SCHEDULE: Zero prior to the first anniversary of the Date of Grant; ⅓ on the first anniversary of the Date of Grant; an additional ⅓ on the second anniversary of the Date of Grant; and an additional ⅓ on the third anniversary of the Date of Grant (each such anniversary of the Date of Grant being a “Vesting Date”)

PURCHASE PRICE PER SHARE: See Morgan Stanley Benefit Access “Stock Options and SARs /My Grants/Grant Price”

The following Terms and Conditions (these “Terms and Conditions”) are set forth as of the Date of Grant between OCCIDENTAL PETROLEUM CORPORATION, a Delaware corporation (“OXY” and, with its subsidiaries, the “Company”), and the eligible employee receiving this award (the “Grantee”).

1.Grant of Option. In accordance with these Terms and Conditions and the Occidental Petroleum Corporation 2005 Long-Term Incentive Plan, as the same may be amended from time to time (the “Plan”), OXY hereby grants to the Grantee as of the Date of Grant the right and option (“Option”) to purchase all or any part of the aggregate number of shares of OXY common stock, $0.20 par value (“Common Stock”), set forth above. In the event of any conflict between the terms of these Terms and Conditions and the Plan, the Plan shall control. Capitalized terms used but not defined in these Terms and Conditions shall have the meanings attributed to such terms under the Plan, unless the context requires otherwise. This Option shall not be treated as an incentive stock option within the meaning of section 422(b) of the Code.

If the Grantee fails to accept this award prior to the first record date for the payment of dividends on the Common Stock subsequent to the Date of Grant, then, notwithstanding any other provision of this award, the Grantee shall forfeit this Option and all rights under this award and this award will become null and void. For purposes of these Terms and Conditions, acceptance of the award shall occur on the date the Grantee accepts this Nonstatutory Stock Option Award through Morgan Stanley Benefit Access or any replacement on-line system designated by the Company.

2.Purchase Price. The purchase price per share of Common Stock purchasable pursuant to the exercise of this Option shall be the purchase price per share set forth above, which has been determined to be equal to the Fair Market Value of a share of Common Stock at the Date of Grant. For all purposes of these Terms and Conditions, the Fair Market Value of a share of Common Stock shall be determined in accordance with the provisions of the Plan.

3.Vesting of Option. The Grantee cannot exercise the Option until the right to exercise has vested. The Grantee will become vested in the aggregate number of shares of Common Stock offered by this Option as determined under the vesting schedule set forth above, provided the Grantee remains in the employ of, or a service provider to, the Company until each applicable Vesting Date. The continuous employment of the Grantee will not be deemed to have been interrupted by reason of the transfer of the Grantee’s employment among the Company and its affiliates or an approved leave of absence. Notwithstanding the foregoing:

(a)if, prior to the final Vesting Date, the Grantee dies, becomes permanently disabled while in the employ of the Company and terminates employment as a result thereof, retires with the written consent of the Company, or terminates employment without cause (as determined by the Company) for the convenience of the Company (each of the foregoing, a “Forfeiture Event”), then the unvested portion of this Option will be reduced on a pro rata basis based upon the number obtained by (i) multiplying the aggregate number of shares of Common Stock offered by this Option by a fraction, the numerator of which is the number of days between the Date of Grant and the Forfeiture Event, and the denominator of which is the number of days between the Date of Grant and the final Vesting Date, and (ii) subtracting from the product the number of shares of Common Stock with respect to which this Option became vested and exercisable prior to the Forfeiture Event. This Option shall become vested and exercisable with respect to such pro rata unvested shares of Common Stock offered by this Option as of the date of the Forfeiture Event, and this Option shall cease to be exercisable as of such date with respect to any other shares of Common Stock offered under this Option that have not become vested and exercisable on or prior to such date; and

(b)if a Change in Control occurs prior to the final Vesting Date and the Grantee’s employment is terminated by the Company on or after the date of such event and as a result of such event, then this Option shall become fully vested and exercisable as of the date of such termination of employment unless, prior to the occurrence of the Change in Control, the Committee, as provided in Section 7.1 of the Plan, determines that such event will not accelerate the vesting and exercisability of this Option. Any such determination by the Committee is binding on the Grantee.

    If the Grantee terminates employment voluntarily or the Grantee’s employment is terminated for cause (as determined by the Company) before the final Vesting Date, then the Grantee shall forfeit the portion of this Option that has not become vested and exercisable prior to the Grantee’s termination date.

4.Exercise of Option. Subject to the earlier expiration of this Option pursuant to Section 5, the vested portion of this Option may be exercised, by written notice to OXY at its principal executive office addressed to the attention of its corporate secretary (or such other officer, employee or designee of the Company as OXY may designate from time to time), at any time and from time to time after the Date of Grant but prior to the Expiration Time (as defined below). The notice must specify that this Option (or a portion thereof) is being exercised and the number of shares with respect to which this Option is being exercised. This Option may only be exercised as provided in these Terms and Conditions and in accordance with such rules and regulations as may, from time to time, be adopted by the Committee. The exercise of this Option shall be deemed effective upon receipt by OXY of the notice and payment described herein. As soon as practicable after the effective exercise of this Option, and upon satisfaction of all applicable withholding requirements, the Grantee shall be recorded on OXY’s stock transfer books as the owner of the Shares purchased.

    The purchase price of shares as to which this Option is exercised shall be paid in full at the time of exercise (i) in cash, cash equivalents, or by electronic funds transfer, (ii) if permitted by the Committee in its sole discretion, by delivering or constructively tendering to OXY shares of Common Stock having a Fair Market Value equal to the purchase price (provided such shares used for this purpose must have been held by the Grantee for such minimum period of time as may be established from time to time by the Committee), (iii) if the Common Stock is readily tradable on a national securities exchange, through a “cashless exercise” in accordance with a Company established policy or program for the same, or (iv) in any other legal consideration the Committee deems appropriate. No fraction of a share of Common Stock shall be issued by OXY upon exercise of an Option or accepted by OXY in payment of the exercise price thereof; rather, the Grantee shall provide a cash payment for such amount as is necessary to effect the issuance and acceptance of only whole shares of Common Stock. Unless and until the date that shares of Common Stock are issued by OXY to the Grantee following exercise of the Option, the Grantee (or the person permitted to exercise this Option in the event of the Grantee’s death) shall not be or have any of the rights or privileges of a stockholder of OXY with respect to shares acquirable upon an exercise of this Option.

5.Expiration. This Option shall expire (and shall cease to be outstanding) at the close of business on the seventh anniversary of the Date of Grant (the “Expiration Time”); provided, that if the Grantee terminates employment voluntarily or the Grantee’s employment is terminated for cause (as determined by the Company) before the final Vesting Date, then this Option may be exercised by the Grantee (or the person who acquires this Option by will or the laws of descent and distribution or otherwise by reason of the death of Grantee) at any time during the period of 90 days following such termination, but only as to the number of shares the Grantee was entitled to purchase hereunder as of the date the Grantee’s employment so terminates.

6.Taxes and Withholding. Regardless of any action the Company takes with respect to any or all income tax (including U.S. federal, state and local tax and non-U.S. tax), social insurance, payroll tax, payment on account or other tax-related items related to the Grantee’s participation in the Plan and legally applicable to the Grantee (“Tax-Related Items”), the Grantee acknowledges that the ultimate liability for all Tax-Related Items is and remains the Grantee’s responsibility and may exceed the amount actually withheld by the Company. The Grantee further acknowledges that

the Company (i) makes no representations or undertakings regarding the treatment of any Tax-Related Items in connection with any aspect of this Option, including the grant, vesting or exercise of the Option; and (ii) does not commit to and is under no obligation to structure the terms of the grant or any aspect of the Option to reduce or eliminate the Grantee’s liability for Tax-Related Items or achieve any particular tax result. Further, if the Grantee has become subject to tax in more than one jurisdiction between the Date of Grant and the date of any relevant taxable event, the Grantee acknowledges that the Company may be required to withhold or account for Tax-Related Items in more than one jurisdiction.

Prior to the relevant taxable event, the Grantee shall pay or make adequate arrangements satisfactory to the Company to satisfy all Tax-Related Items. In this regard, the Grantee authorizes the Company to withhold all applicable Tax-Related Items legally payable by the Grantee, first, from the shares purchased upon exercise of this Option and, if not sufficient, from the Grantee’s wages or other cash compensation. The Grantee shall pay to the Company any amount of Tax-Related Items that the Company may be required to withhold as a result of the Grantee’s receipt, vesting or exercise of this Option that cannot be satisfied by the means previously described.

7.Status of Common Stock. OXY intends to register for issuance under the Securities Act of 1933, as amended (the “Act”), the shares of Common Stock acquirable upon exercise of this Option, and to keep such registration effective throughout the period this Option is exercisable. In the absence of such effective registration or an available exemption from registration under the Act, issuance of shares of Common Stock acquirable upon exercise of this Option will be delayed until registration of such shares is effective or an exemption from registration under the Act is available. OXY intends to use its reasonable efforts to ensure that no such delay will occur. In the event exemption from registration under the Act is available upon an exercise of this Option, the Grantee (or the person permitted to exercise this Option in the event of the Grantee’s death or incapacity), if requested by the Company to do so, will execute and deliver to the Company in writing an agreement containing such provisions as the Company may require to assure compliance with applicable securities laws.

The Grantee agrees that the shares of Common Stock which the Grantee may acquire by exercising this Option will not be sold or otherwise disposed of in any manner which would constitute a violation of any applicable federal or state securities laws. The Grantee also agrees that (i) any certificates representing the shares of Common Stock purchased under this Option may bear such legend or legends as the Committee deems appropriate in order to assure compliance with applicable securities laws, (ii) OXY may refuse to register the transfer of the shares of Common Stock purchased under this Option on the stock transfer records of OXY if such proposed transfer would in the opinion of counsel satisfactory to OXY constitute a violation of any applicable securities law, and (iii) OXY may give related instructions to its transfer agent, if any, to stop registration of the transfer of the shares of Common Stock purchased under this Option.

8.No Employment Contract. Nothing in these Terms and Conditions confers upon the Grantee any right with respect to continued employment by the Company, nor limits in any manner the right of the Company to terminate the employment or adjust the compensation of the Grantee. Unless otherwise agreed in a writing signed by the Grantee and an authorized representative of the Company, the Grantee’s employment with the Company is at will and may be terminated at any time by the Grantee or the Company.

9.Grantee’s Representations and Releases. By accepting this Option, the Grantee acknowledges that the Grantee has read these Terms and Conditions and understands that (i) the grant of this Option is made voluntarily by OXY in its discretion with no liability on the part of any of its direct or indirect subsidiaries and that, if the Grantee is not an employee of OXY, the Grantee is not, and will not be considered, an employee of OXY but the Grantee is a third party (employee of a subsidiary) to whom this Option is granted; (ii) all decisions with respect to future awards, if any, will be at the sole discretion of OXY; (iii) the Grantee’s participation in the Plan is voluntary; (iv) this Option is an extraordinary item that does not constitute a regular and recurring item of base compensation; (v) the future value of any Shares that may be purchased pursuant to this Option cannot be predicted and OXY does not assume liability in the event this Option or any purchased Shares have no value in the future; (vi) subject to the terms of any tax equalization agreement between the Grantee and the entity employing the Grantee, the Grantee will be solely responsible for the payment or nonpayment of taxes imposed or threatened to be imposed by any authority of any jurisdiction; (vii) OXY is not providing any tax, legal or financial advice with respect to this Option or the Grantee’s participation in the Plan; and (viii) if the purchase price of the Common Stock under this Option is less than the fair market value of such Common Stock on the date of grant of this Option, then the Grantee may incur adverse tax consequences under section 409A of the Code. The Grantee acknowledges and agrees that (a) he is not relying upon any determination by the Company, any Affiliate, or any of their respective employees, directors, managers, officers, attorneys or agents (collectively, the “Company Parties”) of the fair market value of the Common Stock on the date of grant of this Option, (b) he is not relying upon any written or oral statement or representation of the Company Parties regarding the tax effects associated with the Grantee’s acceptance of these Terms and Conditions and his receipt, holding and exercise of this Option, and (c) in deciding to accept these Terms and Conditions, the Grantee is relying on his own judgment and the judgment of the professionals of his choice with whom he has consulted. The Grantee hereby releases, acquits and forever discharges the Company Parties from all actions, causes of actions, suits, debts, obligations, liabilities, claims, damages, losses, costs and expenses of any nature whatsoever, known or unknown, on account of, arising out of, or in any way related to the tax effects associated with the Grantee’s acceptance of these Terms and Conditions and his receipt, holding and exercise of this Option or related to the termination of the Option or diminution in value of the Option resulting from termination of the Grantee’s employment by the Company (for any reason whatsoever).

By accepting this Option, the Grantee agrees, to the extent not contrary to applicable law, to the General Terms of Employment set out on Attachment 1 and the Arbitration Provisions set out on Attachment 2, which, in each case, are incorporated in these Terms and Conditions by reference.

10.Notices. Any notices or other communications provided for in these Terms and Conditions shall be sufficient if in writing. In the case of the Grantee, such notices or communications shall be effectively delivered if hand delivered to the Grantee at the Grantee’s principal place of employment or if sent by certified mail, return receipt requested, to the Grantee at the last address the Grantee has filed with the Company. In the case of the Company, such notices or communications shall be effectively delivered if sent by certified mail, return receipt requested, to OXY at its principal executive offices.

11.Privacy Rights. By accepting this Option, the Grantee explicitly and unambiguously consents to the collection, use and transfer, in electronic or other form, of the Grantee’s Data (as defined below) by and among, as applicable, the Company and its affiliates for the exclusive purpose of implementing, administering and managing the Grantee’s participation in the Plan. The Company holds or may receive from any agent designated by the Company certain personal information about the Grantee, including, but not limited to, the Grantee’s name, home address and telephone number, date of birth, social insurance number or other identification number, salary, nationality, job title, any shares of stock or directorships held in the Company, details of this Option or any other entitlement to cash or shares of stock awarded, canceled, exercised, vested, unvested or outstanding in the Grantee’s favor, for the purpose of implementing, administering and managing the Plan, including complying with applicable tax and securities laws (“Data”). Data may be transferred to any third parties assisting in the implementation, administration and management of the Plan. These recipients may be located in the Grantee’s country or elsewhere, and may have different data privacy laws and protections than the Grantee’s country. By accepting these Terms and Conditions, the Grantee authorizes the recipients to receive, possess, use, retain and transfer the Data, in electronic or other form, for the purposes described above. The Grantee may, at any time, view Data, request additional information about the storage and processing of Data, require any necessary amendments to Data or refuse or withdraw the consents herein, in any case without cost, by contacting the Committee in writing. Refusing or withdrawing consent may affect the Grantee’s ability to participate in the Plan.

12.Electronic Delivery and Acceptance. The Company may, in its sole discretion, decide to deliver any documents related to this Option granted under the Plan or future awards that may be granted under the Plan (if any) by electronic means or to request the Grantee’s consent to participate in the Plan by electronic means. The Grantee hereby consents to receive such documents by electronic delivery and, if requested, to participate in the Plan through an on-line or electronic system established and maintained by the Company or another third party designated by the Company.

13.Binding Effect. These Terms and Conditions shall be binding upon and inure to the benefit of any successors to the Company and all persons lawfully claiming under the Grantee.

14.Entire Agreement; Amendment. These Terms and Conditions and the Attachments incorporated in these Terms and Conditions constitute the entire agreement of the parties with regard to the subject matter hereof, and contain all the covenants, promises, representations, warranties and agreements between the parties with respect to this Option; provided, however, that the terms of these Terms and Conditions shall not modify and shall be subject to the terms and conditions of

any employment and/or severance agreement between the Company (or an affiliate) and the Grantee in effect as of the date a determination is to be made under these Terms and Conditions. Without limiting the scope of the preceding sentence, except as provided therein, all prior understandings and agreements, if any, among the parties hereto relating to the subject matter hereof are hereby null and void and of no further force and effect. The Committee may, in its sole discretion, amend these Terms and Conditions from time to time in any manner that is not inconsistent with the Plan; provided, however, that except as otherwise provided in the Plan or these Terms and Conditions, no amendment will adversely affect the rights of the Grantee under these Terms and Conditions in any material respect without the Grantee’s consent.

15.Compliance with Law. The Company will make reasonable efforts to comply with all federal, state and non-U.S. laws applicable to awards of this type. However, if it is not feasible for the Company to comply with these laws with respect to the grant or settlement of these awards, then the awards may be cancelled without any compensation or additional benefits provided to Grantee as a result of the cancellation.

16.Relation to Other Benefits. The benefits received by the Grantee under these Terms and Conditions will not be taken into account in determining any benefits to which the Grantee may be entitled under any profit sharing, retirement or other benefit or compensation plan maintained by the Company, including the amount of any life insurance coverage available to any beneficiary of the Grantee under any life insurance plan covering employees of the Company. Additionally, this Option is not part of normal or expected compensation or salary for any purposes, including but not limited to calculation of any severance, resignation, termination, redundancy, end of service payments, bonuses or long-service awards. The grant of this Option does not create any contractual or other right to receive future grants of Options or benefits in lieu of Options, even if Grantee has a history of receiving Options or other cash or stock awards.

17.Severability. If one or more of the provisions of these Terms and Conditions is invalidated for any reason by a court of competent jurisdiction, the invalidated provisions shall be deemed to be separable from the other provisions of these Terms and Conditions, and the remaining provisions of these Terms and Conditions will continue to be valid and fully enforceable.

18.Governing Law. The laws of the State of Delaware govern the interpretation, performance, and enforcement of these Terms and Conditions.

Attachment 1General Terms of Employment

A.Except as otherwise required by law or legal process, the Grantee will not publish or divulge to any person, firm, corporation or institution and will not use to the detriment of OXY, or any of its subsidiaries or other affiliates, or any of their respective officers, directors, employees or stockholders (collectively, “OXY Parties”), at any time during or after the Grantee’s employment by any of them, any trade secrets or confidential information of any of them (whether generated by them or as a result of any of their business relationships), including such information as described in OXY’s ethics code and other corporate policies, without first obtaining the written permission of an officer of the Company.

B.At the time of leaving employment with the Company, the Grantee will deliver to the Company, and not keep or deliver to anyone else, any and all credit cards, drawings, blueprints, specifications, devices, notes, notebooks, memoranda, reports, studies, correspondence and other documents, and, in general, any and all materials relating to the OXY Parties (whether generated by them or as a result of their business relationships), including any copies (whether in paper or electronic form), that the Grantee has in the Grantee’s possession or control.

C.The Grantee will, during the Grantee’s employment by the Company, comply with the provisions of OXY’s Code of Business Conduct.

D.Except as otherwise required by the Grantee’s job or permitted by law, the Grantee will not make statements about any OXY Parties (1) to the press, electronic media, to any part of the investment community, to the public, or to any person connected with, employed by or having a relationship with any of them without permission of an officer of the Company or (2) that are derogatory, defamatory or negative. Nothing herein, however, shall prevent Grantee from making a good faith report or complaint to appropriate governmental authorities. To the fullest extent permitted by law, Grantee will not interfere with or disrupt any of the Company’s operations or otherwise take actions intended directly to harm any of the OXY Parties.

E.All inventions, developments, designs, improvements, discoveries and ideas that the Grantee makes or conceives in the course of employment by the Company, whether or not during regular working hours, relating to any design, article of manufacture, machine, apparatus, process, method, composition of matter, product or any improvement or component thereof, that are manufactured, sold, leased, used or under development by, or pertain to the present or possible future business of the Company shall be a work-for-hire and become and remain the property of OXY, its successors and assigns.

F.The foregoing General Terms of Employment are not intended to be an exclusive list of the employment terms and conditions that apply to the Grantee. The Company, in its sole discretion, may at any time amend or supplement the foregoing terms. The Grantee’s breach of the foregoing General Terms of Employment will entitle the Company to take appropriate disciplinary action, including, without limitation, reduction of the Option granted pursuant to these Terms and Conditions and termination of employment.

Attachment 2ARBITRATION PROVISIONS

ANY DISPUTE ARISING OUT OF OR IN ANY WAY RELATED TO THE GRANTEE’S EMPLOYMENT WITH THE COMPANY, OR THE TERMINATION OF THAT EMPLOYMENT, WILL BE DECIDED EXCLUSIVELY BY FINAL AND BINDING ARBITRATION AT A LOCATION WITHIN 50 MILES OF THE COMPANY OFFICE AT OR CLOSEST TO EMPLOYEE’S PRIMARY WORK LOCATION, PURSUANT TO ANY PROCEDURES REQUIRED BY APPLICABLE LAW. TO THE EXTENT NOT INCONSISTENT WITH APPLICABLE LAW, ANY ARBITRATION WILL BE SUBMITTED TO THE AMERICAN ARBITRATION ASSOCIATION (“AAA”) AND SUBJECT TO AAA EMPLOYMENT ARBITRATION RULES AND MEDIATION PROCEDURESIN EFFECT AT THE TIME OF FILING OF THE DEMAND FOR ARBITRATION. THE AAA EMPLOYMENT ARBITRATION RULES AND MEDIATION PROCEDURES ARE AVAILABLE ONLINE AT WWW.ADR.ORG. YOU MAY ALSO CALL AAA AT 800.778.7879 IF THERE ARE QUESTIONS ABOUT THE ARBITRATION PROCESS. ONLY THE FOLLOWING CLAIMS ARE EXCLUDED FROM THESE TERMS AND CONDITIONS: (1) CLAIMS FOR WORKERS’ COMPENSATION, UNEMPLOYMENT COMPENSATION, OR STATE DISABILITY BENEFITS, AND CLAIMS BASED UPON ANY PENSION OR WELFARE BENEFIT PLAN THE TERMS OF WHICH CONTAIN AN ARBITRATION OR OTHER NON-JUDICIAL DISPUTE RESOLUTION PROCEDURE, (2) TO THE EXTENT PERMITTED BY APPLICABLE LAW, CLAIMS FOR PROVISIONAL REMEDIES TO MAINTAIN THE STATUS QUO PENDING THE OUTCOME OF ARBITRATION, (3) CLAIMS BASED ON COMPENSATION AWARD AGREEMENTS AND INCENTIVE PLANS AND (4) CLAIMS WHICH ARE NOT PERMITTED BY APPLICABLE LAW TO BE SUBJECT TO A BINDING PRE-DISPUTE ARBITRATION AGREEMENT.

ANY CONTROVERSY REGARDING WHETHER A PARTICULAR DISPUTE IS SUBJECT TO ARBITRATION UNDER THIS ARBITRATION PROVISION SHALL BE DECIDED BY A NEUTRAL ARBITRATOR SELECTED BY AGREEMENT OF GRANTEE AND THE COMPANY OR OTHERWISE SELECTED IN ACCORDANCE WITH AAA EMPLOYMENT ARBITRATION RULES AND MEDIATION PROCEDURES.

TO THE EXTENT REQUIRED UNDER APPLICABLE LAW, THE GRANTEE’S RESPONSIBILITY FOR PAYMENT OF THE NEUTRAL ARBITRATOR’S FEES AND EXPENSES SHALL BE LIMITED TO AN AMOUNT EQUAL TO THE FILING FEE THAT WOULD BE REQUIRED FOR A STATE TRIAL COURT ACTION AND THE COMPANY SHALL PAY ALL REMAINING FEES AND EXPENSES OF THE ARBITRATOR. UNLESS OTHERWISE REQUIRED UNDER APPLICABLE LAW, THE PARTIES SHALL EACH PAY THEIR PRO RATA SHARE OF THE NEUTRAL ARBITRATOR’S EXPENSES AND FEES. ANY CONTROVERSY REGARDING THE PAYMENT OF FEES AND EXPENSES UNDER THIS ARBITRATION PROVISION SHALL BE DECIDED BY THE NEUTRAL ARBITRATOR.

9

THE NEUTRAL ARBITRATOR WILL ALLOW FOR ADEQUATE DISCOVERY BY BOTH PARTIES AND MAY AWARD ANY FORM OF REMEDY OR RELIEF (INCLUDING INJUNCTIVE RELIEF) THAT WOULD OTHERWISE BE AVAILABLE IN COURT. ANY AWARD PURSUANT TO SAID ARBITRATION SHALL BE ACCOMPANIED BY A WRITTEN OPINION OF THE ARBITRATOR SETTING FORTH THE REASON FOR THE AWARD. THE AWARD RENDERED BY THE ARBITRATOR SHALL BE CONCLUSIVE AND BINDING UPON THE PARTIES HERETO, AND JUDGMENT UPON THE AWARD MAY BE ENTERED, AND ENFORCEMENT MAY BE SOUGHT IN, ANY COURT OF COMPETENT JURISDICTION. TO THE EXTENT NOT INCONSISTENT WITH APPLICABLE LAWS, THE ARBITRATOR WILL HAVE THE AUTHORITY TO HEAR AND GRANT MOTIONS.

THIS AGREEMENT TO ARBITRATE IS FREELY AGREED TO BETWEEN GRANTEE AND THE COMPANY AND IS MUTUALLY ENTERED INTO BETWEEN THE PARTIES. EACH PARTY FULLY UNDERSTANDS AND AGREES THAT THEY ARE GIVING UP CERTAIN RIGHTS OTHERWISE AFFORDED TO THEM BY CIVIL COURT ACTIONS, INCLUDING BUT NOT LIMITED TO THE RIGHT TO A JURY TRIAL.

EX-12

EXHIBIT 12

OCCIDENTAL PETROLEUM CORPORATION AND SUBSIDIARIES

COMPUTATION OF TOTAL ENTERPRISE RATIOS OF EARNINGS TO FIXED CHARGES

(Amounts in millions, except ratios)

For the years ended December 31,	2014				2013		2012		2011				2010
Income from continuing operations (a)	$	(130	)		$	4,932	$	3,829	$	5,527			$	3,851
Subtract:
Net income attributable to noncontrolling interest	(14		)		—		—		—				(72		)
Adjusted income from equity investments (b)	64				52		163		(33		)		(60		)
	(80		)		4,984		3,992		5,494				3,719
Add:
Provision for taxes on income (other than foreign oil and gas taxes)	(280		)		1,353		249		1,167				671
Interest and debt expense	77				132		149		313			(c)	133
Portion of lease rentals representative of the interest factor	52				60		58		57				55
	(151		)		1,545		456		1,537				859
Earnings before fixed charges	$	(231	)		$	6,529	$	4,448	$	7,031			$	4,578
Fixed charges:
Interest and debt expense including capitalized interest	$	257			$	269	$	254	$	384		(c)	$	204
Portion of lease rentals representative of the interest factor	52				60		58		57				55
Total fixed charges	$	309			$	329	$	312	$	441			$	259
Ratio of earnings to fixed charges	(0.75		)		19.83		14.26		15.93				17.65
Insufficient coverage	$	(540	)	(d)	$	—	$	—	$	—			$	—

Note:  Results of California Resources Corporation have been reflected as discontinued operations for all periods presented.

(a)	The 2014 amounts includes a $4.2 billion dollar after-tax impairment charge related to the decline in crude oil market prices, a $338 million after-tax gain for the sale of the Hugoton assets, a $403 million after-tax gain for the sale of the BridgeTex assets, a $861 million after-tax gain for the sale of a portion of an investment in the General Partner of Plains All-American Pipeline L.P., and a $1.2 billion after-tax impairment related to Josyln and mark to market adjustments for Oxy's California Resources investment. The 2013 amount includes a $624 million after-tax gain for the sale of a portion of an investment in the General Partner of Plains All-American Pipeline L.P., a $85 million after-tax gain for the sale of an investment in Carbocloro, a Brazilian chemical facility and $387 million of after-tax charges related to the impairment of non-producing domestic acreage. The 2012 amount 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.
(d)	The 2014 ratio of earnings to fixed charges excluding certain items (a) is 11.96

EX-21

EXHIBIT 21

LIST OF SUBSIDIARIES

The following is a list of the Registrant’s subsidiaries at December 31, 2014.

Name	Jurisdiction of Formation
Armand Products Company	Delaware
Bravo Pipeline Company	Delaware
BridgeTex Pipeline Company, LLC	Delaware
Centurion Pipeline GP, Inc.	Delaware
Centurion Pipeline L.P.	Delaware
Centurion Pipeline LP, Inc.	Delaware
Concord Petroleum Corporation	Panama
Conn Creek Shale Company	Delaware
D.S. Ventures, LLC	Texas
DMM Financial LLC	Delaware
Downtown Plaza II	Oklahoma
Glenn Springs Holdings, Inc.	Delaware
Grand Bassa Tankers, Inc.	Delaware
Grupo OxyChem de Mexico, S.A. de C.V.	Mexico
Hooker Chemical Investment Co.	California
INDSPEC Chemical B.V.	Netherlands
INDSPEC Chemical Corporation	Delaware
INDSPEC Chemical Export Sales, LLC	Delaware
INDSPEC Holding Corporation	Delaware
Ingleside Cogeneration GP 2, Inc.	Delaware
Ingleside Cogeneration GP, Inc.	Delaware
Ingleside Cogeneration Limited Partnership	Delaware
Interore Trading Ltd.	Liberia
Ingleside Ethylene, LLC	Delaware
Joslyn Partnership	Alberta, Canada
Laguna Petroleum Corporation	Texas
Mariana Properties, Inc.	Delaware
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 (Colombia Block), Inc.	Nevis
Occidental (East Shabwa), LLC	Nevis
Occidental Advance Sale Finance, Inc.	California
Occidental Andina, LLC	Delaware
Occidental Angola (Block 23) Holdings Ltd.	Bermuda
Occidental Angola (Block 8) Holdings Ltd.	Bermuda

EXHIBIT 21 (cont'd)

Name	Jurisdiction of Formation
Occidental Angola Holdings Ltd.	Bermuda
Occidental Angola, Inc.	California
Occidental Brazil Holdings, Inc.	Nevis
Occidental Brazil Investments, LLC	Nevis
Occidental Canada Holdings Ltd.	Nova Scotia
Occidental Chemical Asia, Limited	Japan
Occidental Chemical Belgium B.V.B.A.	Belgium
Occidental Chemical Chile Limitada	Chile
Occidental Chemical Corporation	New York
Occidental Chemical de Mexico, S.A. de C.V.	Mexico
Occidental Chemical Export Sales, LLC	Delaware
Occidental Chemical Far East Limited	Hong Kong
Occidental Chemical Holding Corporation	California
Occidental Chemical International, Inc.	California
Occidental Chemical Investment (Canada) I, Inc.	Delaware
Occidental Chemical Nevis, Inc.	Nevis
Occidental Chile Investments, LLC	Delaware
Occidental Chile Minority Holder, LLC	Delaware
Occidental CIS Services, Inc.	Delaware
Occidental Colombia (Series G) Ltd.	Bermuda
Occidental Colombia (Series J) Ltd.	Bermuda
Occidental Colombia (Series K) Ltd.	Bermuda
Occidental Colombia (Series L) Ltd.	Bermuda
Occidental Colombia (Series M) Ltd.	Bermuda
Occidental Colombia (Series N) Ltd.	Bermuda
Occidental Colombia (Series O) 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 LLC	Delaware
Occidental EOR (Algeria) Ltd.	Bermuda
Occidental Explorado del Peru Ltd.	Bermuda
Occidental Exploration and Production Company	California
Occidental Exploration Ltd.	Bermuda
Occidental International (Libya), Inc.	Delaware
Occidental International Corporation	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

EXHIBIT 21 (cont'd)

Name	Jurisdiction of Formation
Occidental Libya Oil & Gas B.V.	The Netherlands
Occidental LNG (Malaysia) Ltd.	Bermuda
Occidental MENA Manager Ltd.	Bermuda
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 Albania (Onshore-2) Ltd.	Bermuda
Occidental of Albania (Onshore-3) 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 (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 Bangladesh, Inc.	Delaware
Occidental of Colombia (Caimanes), Inc.	Nevis
Occidental of Colombia (Chipiron), Inc.	Nevis
Occidental of Colombia (Cocodrilos), Inc.	Nevis
Occidental of Colombia (Cosecha), Inc.	Nevis
Occidental of Colombia (Los Gavilanes), Inc.	Nevis
Occidental of Colombia (Medina), Inc.	Nevis
Occidental of Colombia (Siriri), Inc.	Nevis
Occidental of Colombia (Teca), Inc.	Nevis
Occidental of Dubai, Inc.	Nevis
Occidental of Iraq Holdings Ltd.	Bermuda
Occidental of Iraq, LLC	Delaware
Occidental of Oman, Inc.	Nevis
Occidental of Russia Ltd.	Bermuda
Occidental of South Africa (Offshore), Inc.	Nevis
Occidental of the Adriatic Ltd.	Bermuda
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 International Inc.	Delaware
Occidental Oil and Gas International, LLC	Delaware
Occidental Oil and Gas of Peru, LLC	Delaware
Occidental Oil and Gas Pakistan LLC	Nevis
Occidental Oil and Gas (Oman) Ltd.	Nevis
Occidental Oil Asia Pte. Ltd.	Singapore
Occidental Oil Shale Inc.	California
Occidental Oman (Block 27) Holdings Ltd.	Bermuda
Occidental Oman Gas Company LLC	Delaware
Occidental Oman Gas Holdings Ltd.	Bermuda

EXHIBIT 21 (cont'd)

Name	Jurisdiction of Formation
Occidental OOOI Holder, Inc.	Delaware
Occidental Oriente Exploration and Production Ltd.	Cayman Islands
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 Peruana, Inc.	California
Occidental Petrolera de Argentina Ltd.	Bermuda
Occidental Petrolera del Peru (Block 101), Inc.	Nevis
Occidental Petrolera del Peru (Block 103), Inc.	Nevis
Occidental Petroleum (Pakistan), Inc.	Delaware
Occidental Petroleum Corporation Political Action Committee	California
Occidental Petroleum de Venezuela S.A.	Venezuela
Occidental Petroleum of Nigeria	Nigeria
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 Red Sea Development, LLC	Nevis
Occidental Research Corporation	California
Occidental Resource Recovery Systems, Inc.	California
Occidental Resources Company	Cayman Islands
Occidental Shah Gas Holdings Ltd.	Bermuda
Occidental South America Finance, LLC	Delaware
Occidental Specialty Marketing, Inc.	Delaware
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 Ecuador Management, LLC	Delaware
OOOI Oil and Gas Management, Inc.	Delaware
OOOI Oil and Gas Sub, LLC	Delaware
OOOI South America Management, LLC	Delaware
Opcal Insurance, Inc.	Hawaii
OPM GP, Inc.	Delaware
Oxy BridgeTex Limited Partnership	Texas

EXHIBIT 21 (cont'd)

Name	Jurisdiction of Formation
Oxy BT Holdings GP, Inc.	Texas
Oxy BT Holdings LP, Inc.	Texas
Oxy C & I Bulk Sales, LLC	Delaware
Oxy Canada Sales, Inc.	Delaware
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, LLC	Delaware
Oxy Expatriate Services, Inc.	Delaware
Oxy FFT Holdings, Inc.	Delaware
Oxy Holding Company (Pipeline), Inc.	Delaware
OXY Inc.	California
Oxy Ingleside Energy Center, LLC	Delaware
Oxy Ingleside LPG Pipeline, LLC	Delaware
Oxy Ingleside LPG Storage Company, LLC	Delaware
Oxy Ingleside LPG Terminal, LLC	Delaware
Oxy Ingleside Oil Pipeline, LLC	Delaware
Oxy Ingleside Oil Storage Company, LLC	Delaware
Oxy Ingleside Oil Terminal, LLC	Delaware
Oxy Levelland Pipeline Company, LLC	Delaware
Oxy Levelland Terminal Company, LLC	Delaware
OXY Libya E&P Area 106 Ltd.	Bermuda
OXY Libya E&P Area 124 Ltd.	Bermuda
OXY Libya E&P Area 131 Ltd.	Bermuda
OXY Libya E&P Area 163 Ltd.	Bermuda
OXY Libya E&P Area 35 Ltd.	Bermuda
OXY Libya E&P Area 36 Ltd.	Bermuda
OXY Libya E&P Area 52 Ltd.	Bermuda
OXY Libya E&P Area 53 Ltd.	Bermuda
OXY Libya E&P Area 59 Ltd.	Bermuda
OXY Libya E&P Concession 103 Ltd.	Bermuda
OXY Libya E&P EPSA 1981 Ltd.	Bermuda
OXY Libya E&P EPSA 1985 Ltd.	Bermuda
OXY Libya Exploration, SPC	Cayman Islands
OXY Libya, LLC	Delaware
OXY Little Knife, LLC	Delaware
OXY LPG LLC	Delaware
Oxy LPG Terminal, LLC	Delaware
OXY Mexico Holdings I, LLC	Delaware
OXY Mexico Holdings II, LLC	Delaware
OXY Middle East Holdings Ltd.	Bermuda
Oxy Midstream Holding Company, LLC	Delaware
Oxy Midstream Operating Company, LLC	Delaware
Oxy Midstream Strategic Development LLC	Delaware
OXY of Angola (Block 23), LLC	Delaware
OXY of Angola (Block 8), LLC	Delaware

EXHIBIT 21 (cont'd)

Name	Jurisdiction of Formation
OXY of Saudi Arabia Ltd.	Cayman Islands
OXY Oil Partners, Inc.	Delaware
Oxy Oleoducto SOP, LLC	Delaware
Oxy Overseas Services Ltd.	Bermuda
OXY PBLP Manager, LLC	Delaware
Oxy Pipeline I Company	Delaware
OXY Support Services, LLC	Delaware
Oxy Technology Ventures, Inc.	Delaware
Oxy Transport I Company	Delaware
OXY Tulsa Inc.	Delaware
OXY USA Inc.	Delaware
OXY USA WTP LP	Delaware
Oxy Vinyls Canada Co.	Nova Scotia
Oxy Vinyls Export Sales, LLC	Delaware
Oxy Vinyls, LP	Delaware
OXY VPP Investments, Inc.	Delaware
OXY West, LLC	Texas
Oxy Westwood Corporation	California
Oxy Y-1 Company	New Mexico
OXYCHEM (CANADA), Inc.	Alberta, Canada
OxyChem do Brasil Ltda.	Brazil
OxyChem Ingleside Ethylene Holdings, Inc.	Delaware
Oxychem Shipping Ltd.	Malta
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
Phibro Trading LLC	Delaware
Placid Oil Company	Delaware
Ramlat Oxy Ltd.	Bermuda
Rio de Viento, Inc.	Wyoming
San Patricio Pipeline LLC	Delaware
Scanports Ltd.	United Kingdom
Scanports Shipping, Inc.	Delaware
Shipalks Shipping Ltd.	United Kingdom
Swiflite Aircraft Corporation	New Jersey
Transok Properties, LLC	Delaware
Troy Potter, Inc.	Texas
Turavent Oil AG	Switzerland
Vintage Gas, Inc.	Oklahoma

EXHIBIT 21 (cont'd)

Name	Jurisdiction of Formation
Vintage Petroleum Argentina Ltd.	Cayman Islands
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 Turkey, Inc.	Cayman Islands
VPI MENA Yemen Holdings Ltd.	Bermuda
YT Ranch LLC	Colorado

EX-23.1

EXHIBIT 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in the registration statements (Nos. 333-55404, 333-63444, 333-83124, 333-96951, 333-104827, 333-124732, and 333-142705) on Forms S-3 and S-8 of Occidental Petroleum Corporation of our reports dated February 23, 2015, with respect to the consolidated balance sheets of Occidental Petroleum Corporation and subsidiaries as of December 31, 2014 and 2013, 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, 2014 and the related financial statement schedule II - valuation and qualifying accounts, and the effectiveness of internal control over financial reporting as of December 31, 2014, which reports appear in the December 31, 2014 annual report on Form 10-K of Occidental Petroleum Corporation.

/s/ KPMG LLP

Houston, Texas

February 23, 2015

EX-23.2

EXHIBIT 23.2

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

To the Board of Directors

Occidental Petroleum Corporation:

We consent to the (i) inclusion in the Occidental Petroleum Corporation (Occidental) Form 10-K for the year ended December 31, 2014, and the incorporation by reference in Occidental's registration statements (Nos. 333-55404, 333-63444, 333-83124, 333-96951, 333-104827, 333-124732 and 333-142705) (the “Registration Statements”), of references to our name and to our letter dated January 31, 2015, 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 23, 2015

EX-31.1

EXHIBIT 31.1

RULE 13a – 14(a) / 15d – 14(a)

CERTIFICATION

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

I, Stephen I. Chazen, certify that:

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

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

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

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

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

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

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

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

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

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

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

Date:  February 23, 2015

/s/ STEPHEN I. CHAZEN

Stephen I. Chazen

President and Chief Executive Officer

EX-31.2

EXHIBIT 31.2

RULE 13a – 14(a) / 15d – 14(a)

CERTIFICATION

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

I, Christopher G. Stavros, 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 23, 2015

/s/ CHRISTOPHER G. STAVROS

Christopher G. Stavros

Senior Vice President and

Chief Financial Officer

EX-32.1

EXHIBIT 32.1

CERTIFICATION OF CEO AND CFO PURSUANT TO

18 U.S.C. § 1350,

AS ADOPTED PURSUANT TO

§ 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report on Form 10-K of Occidental Petroleum Corporation (the “Company”) for the fiscal period ended December 31, 2014, as filed with the Securities and Exchange Commission on February 23, 2015 (the “Report”), Stephen I. Chazen, as Chief Executive Officer of the Company, and Christopher G. Stavros, as Chief Financial Officer of the Company, each hereby certifies, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that, to the best of his knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ STEPHEN I. CHAZEN
Name:	Stephen I. Chazen
Title:	President and Chief Executive Officer
Date:	February 23, 2015

/s/ CHRISTOPHER G. STAVROS
Name:	Christopher G. Stavros
Title:	Senior Vice President and Chief Financial Officer
Date:	February 23, 2015

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

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

EX-99.1

EXHIBIT 99.1

OCCIDENTAL PETROLEUM CORPORATION

Process Review

of the

Estimated

Future Proved 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, 2014

\s\ Fred Richoux

Fred P. Richoux, P.E.

TBPE License No. 33949

President

[SEAL]

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

January 30, 2015

Occidental Petroleum Corporation

5 Greenway Plaza, Suite 110

Houston, Texas 77046

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, 2014, 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 December 30, 2014 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, 2014. 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 state of Texas and derived through Occidental’s economic interest as defined in contractual arrangements 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, 2014. 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.

Percentage of Total Company Estimated Net Reserves

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

January 30, 2015

Page 2

Reviewed by Ryder Scott

SEC Parameters

Occidental Petroleum Corporation

As of December 31, 2014

	Oil/Condensate	NGL	Total Liquid Hydrocarbons	Gas	Equivalent MMBOE
Total Proved Developed	20%	31%	22%	25%	23%
Total Proved Undeveloped	20%	43%	24%	37%	27%
Total Company Proved	20%	35%	23%	28%	24%

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 a 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 BOE. 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 BOE basis is, and has been substantially lower than the corresponding price for crude oil currently and for a number of years.

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 by a person who is qualified by experience and training equivalent to that of a Reserves Auditor 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

January 30, 2015

Page 3

Applicable Petroleum Reserves Definitions

The determination of the proved reserves classifications as discussed herein are based on the definitions as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a) released January 14, 2009 in the Federal Register, Volume 74, pages 2158 through 2197.

Reserves and Uncertainty

The SEC defines reserves as the “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserve estimates involve an assessment of the uncertainty relating to the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty as to their recoverability.

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserves quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserves category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty that the estimates of the quantities actually recovered are “much more likely to be achieved than not.” The SEC defines probable reserves as “those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC defines possible reserves as “those additional reserves that are less certain to be recovered than probable reserves.” All quantities of reserves within the same reserves category must meet the SEC definitions as noted above.

The reserves for the properties reviewed by us were estimated by Occidental using deterministic methods and presented as incremental quantities. Under the deterministic incremental approach, discrete quantities of reserves are estimated and assigned separately as proved, probable or possible based on their individual level of uncertainty. At Occidental’s request, this reserves process review addresses only the proved reserves attributable to the properties reviewed herein.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved, probable and possible reserves quantities and their associated reserves categories may be revised due to other factors such as the results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Occidental Petroleum Corporation

January 30, 2015

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, 2014; 2) documenting the changes in reserves from prior estimates; 3) preparing the economic evaluations associated with the estimated December 31, 2014 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 23 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 77 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 2 percent of the proved developed non-producing reserves were estimated by performance methods using analogy to prior established decline trends. The remaining 98 percent of the proved developed non-producing reserves and all of the proved undeveloped reserves were estimated by a combination of methods including volumetrics and 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

January 30, 2015

Page 5

Of the properties reviewed, approximately 94 percent of the proved producing reserves and 42 percent of the proved non-producing and undeveloped reserve volumes are related to the application of enhanced/improved recovery techniques. These enhanced/improved recovery techniques include water and CO₂ injection and infill drilling.

Occidental uses the latest available production, new well and seismic data in its reserves estimation process. Typically, this data is from the third quarter of the year for which reserves are estimated, though material data is considered whenever it becomes available prior to finalization of reserves estimates. The data used by Occidental in their analysis of the proved reserves for the properties reviewed by us was considered sufficient for the purpose thereof.

Primary Economic Assumptions Employed by Occidental for Estimating Reserves

To estimate economically recoverable proved reserves and related future net cash flows, Occidental considered many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. To confirm that the proved reserves reviewed by us meet the SEC requirements to be economically producible, we have reviewed certain primary economic data utilized by Occidental relating to hydrocarbon prices and costs as noted herein.

The hydrocarbon prices in effect on December 31, 2014 for the properties reviewed were determined by Occidental using the unweighted 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 properties located in the Middle East because of 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	$94.99/Bbl	$86.79/Bbl
	NGLs	WTI Cushing	$94.99/Bbl	$42.33/Bbl
	Gas	Henry Hub	$4.41/MMBTU	$4.02/MCF

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Occidental Petroleum Corporation

January 30, 2015

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, 2014. 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 or political obstacles that would significantly alter their plans. While these plans could change from those under existing economic conditions as of December 31, 2014, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

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.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Occidental Petroleum Corporation

January 30, 2015

Page 7

If a decline trend has been established, this trend was used as the basis for estimating future production rates.

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

January 30, 2015

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 and 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, development plans, 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, 2014. 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 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.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Occidental Petroleum Corporation

January 30, 2015

Page 9

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, 2014 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\ Fred Richoux

Fred P. Richoux, P.E.

TBPE License No. 33949

President

[SEAL]

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. Fred Richoux was the primary technical person responsible for preparing the estimates of reserves presented herein.

Richoux, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 1978, is the President and member of the Board of Directors at Ryder Scott. He is responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide as well as other administrative functions at the Company. Before joining Ryder Scott, Richoux served in a number of engineering positions with Phillips Petroleum Company. For more information regarding Mr. Richoux’s geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Experience/Employees.

Richoux earned a Bachelor of Science degree in Electrical Engineering from the University of Louisiana at Lafayette and is a registered Professional Engineer in the State of Texas and the Province of Alberta. He is also a member of the Society of Petroleum Engineers and 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 Richoux fulfills.

Based on his educational background, professional training and more than 45 years of practical experience in the estimation and evaluation of petroleum reserves, Richoux has attained the professional qualifications as a Reserves Estimator [requires appropriate degree and/or is registered as Professional Engineer and has a minimum of 3 years experience in the estimation and evaluation of reserves] and Reserves Auditor [requires appropriate degree and/or is registered as Professional Engineer and has a minimum of 10 years experience in the estimation and evaluation of reserves of which at least 5 years of such experience is being in responsible charge of the estimation and evaluation of reserves] 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.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

Page 2

Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.

Reserves do not include quantities of petroleum being held in inventory.

Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.

RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:

Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

Page 3

PROVED RESERVES (SEC DEFINITIONS) CONTINUED

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)

Sponsored and Approved by:

SOCIETY OF PETROLEUM ENGINEERS (SPE)

WORLD PETROLEUM COUNCIL (WPC)

AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)

SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)

Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).

DEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:

Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Developed Producing (SPE-PRMS Definitions)

While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

Developed Producing Reserves

Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate.

Improved recovery reserves are considered producing only after the improved recovery project is in operation.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

Page 2

Developed Non-Producing

Developed Non-Producing Reserves include shut-in and behind-pipe reserves.

Shut-In

Shut-in Reserves are expected to be recovered from:

(1) completion intervals which are open at the time of the estimate, but which have not started producing;

(2) wells which were shut-in for market conditions or pipeline connections; or

(3) wells not capable of production for mechanical reasons.

Behind-Pipe

Behind-pipe Reserves are expected to be recovered from zones in existing wells, which will require additional completion work or future re-completion prior to start of production.

In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

UNDEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:

Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in [Regulation S-X §210.4-10(a)(2)], or by other evidence using reliable technology establishing reasonable certainty.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

XML

INVESTMENTS AND RELATED-PARTY TRANSACTIONS (Tables)

12 Months Ended

Dec. 31, 2014

INVESTMENTS AND RELATED-PARTY TRANSACTIONS

Summarized financial information of equity-method investments

For the years ended December 31, (in millions)	2014		2013		2012
Revenues	$	3,090	$	3,373	$	2,667
Costs and expenses	2,774		2,987		2,310
Net income	$	316	$	386	$	357
As of December 31, (in millions)	2014		2013
Current assets	$	1,127	$	1,813
Non-current assets	$	2,925	$	4,412
Current liabilities	$	771	$	1,308
Long-term debt	$	1,701	$	2,506
Other non-current liabilities	$	83	$	163
Stockholders’ equity	$	1,498	$	2,248

Related-party transactions

For the years ended December 31, (in millions)	2014		2013		2012
Sales (a)	$	835	$	663	$	419
Purchases	$	6	$	—	$	8
Services	$	27	$	30	$	17
Advances and amounts due from	$	26	$	67	$	25
Amounts due to	$	15	$	3	$	129

(a) In 2014, 2013 and 2012, sales of Occidental-produced oil and NGLs to Plains Pipeline accounted for 46 percent, 72 percent and 80 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.

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Environmental Liabilities and Expenditures (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014 site	Dec. 31, 2013 site	Dec. 31, 2012 site	Dec. 31, 2011
Environmental Liabilities and Expenditures
Environmental remediation reserves, current, included in accrued liabilities	$ 79	$ 78	$ 80
Environmental remediation reserves, noncurrent, included in deferred credits and other liabilities - other	255	252	264
Environmental remediation reserves
Number of Sites	145	157	161
Reserve Balance	334	330	344	360
Environmental reserves, exceeding $ ten million, threshold value	10
Environmental reserves, exceeding $ ten million, number of sites	11
Environmental reserves, range between zero to $ one million site category, number of sites	98
Minimum period of expending second half of environmental reserves	10 years
Environmental remediation additional loss range	380
Environmental costs, including certain estimates by segment
Operating Expenses	194	188	199
Capital Expenditures	189	86	105
Low end of range
Environmental remediation reserves
Environmental reserves, range between zero to $ one million site category	0
Period of expending first half of environmental reserves	3 years
High end of range
Environmental remediation reserves
Environmental reserves, range between zero to $ one million site category	1
Period of expending first half of environmental reserves	4 years
Oil and Gas
Environmental costs, including certain estimates by segment
Operating Expenses	103	100	116
Capital Expenditures	143	67	79
Chemical
Environmental costs, including certain estimates by segment
Operating Expenses	80	75	70
Capital Expenditures	35	14	18
Midstream, Marketing and Other
Environmental costs, including certain estimates by segment
Operating Expenses	11	13	13
Capital Expenditures	11	5	8
Corporate
Environmental costs, including certain estimates by segment
Remediation Expenses	79	60	56
NPL sites
Environmental remediation reserves
Number of Sites	30	31	35
Reserve Balance	23	25	54
Number of sites with significant environmental remediation reserves	2
Percentage of environmental reserves accounted for by associated sites	62.00%
Number of sites indemnified by third party	14
Third-party sites
Environmental remediation reserves
Number of Sites	67	74	75
Reserve Balance	101	83	84
Number of sites with significant environmental remediation reserves	4
Percentage of environmental reserves accounted for by associated sites	56.00%
Number of sites indemnified by third party	8
Number of sites not indemnified by third party	59
Occidental-operated sites
Environmental remediation reserves
Number of Sites	17	20	22
Reserve Balance	107	118	123
Number of sites with significant environmental remediation reserves	4
Percentage of environmental reserves accounted for by associated sites	62.00%
Closed or non-operated Occidental sites
Environmental remediation reserves
Number of Sites	31	32	29
Reserve Balance	$ 103	$ 104	$ 83
Number of sites with significant environmental remediation reserves	4
Percentage of environmental reserves accounted for by associated sites	63.00%

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LONG-TERM DEBT (Details 3) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Principal payments on long-term debt
Due in 2015	$ 0
Due in 2016	1,500,000,000
Due in 2017	1,300,000,000
Due in 2018	500,000,000
Due in 2019	100,000,000
Due in 2020 and thereafter	3,500,000,000
Aggregate future principal payments	6,900,000,000
Other Fixed-Rate and Variable-Rate Debt Disclosures
Estimated fair values of long-term debt	7,000,000,000	7,100,000,000
Debt carrying value	$ 6,857,000,000	$ 6,964,000,000
Variable-rate debt as percent of Occidental's total debt	1.00%	1.00%

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Environmental Liabilities and Expenditures (Details 2) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Environmental reserve activity
Balance - Beginning of Year	$ 330	$ 344	$ 360
Remediation expenses and interest accretion	79	60	56
Spin-off of California Resources	(7)
Payments	(68)	(74)	(72)
Balance - End of Year	$ 334	$ 330	$ 344

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LONG-TERM DEBT (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended			1 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Jun. 30, 2012
Debt instrument
Variable interest rate (as a percent)	0.04%
Long-term debt, gross	$ 6,857	$ 6,964		$ 6,964
Unamortized discount, net	(19)	(25)		(25)
Total long-term debt	6,838	6,939		6,939
Long term debt matured	107	690
Net proceeds from issuance of long-term debt			1,736
Dolphin Energy
Debt instrument
Notional amount of limited recourse guarantees with respect to Dolphin Energy's debt	336	354		354
1.75% senior notes due 2017
Debt instrument
Long-term debt, gross	1,250	1,250		1,250
Debt instrument interest rate stated percentage	1.75%	1.75%		1.75%
4.10% senior notes due 2021
Debt instrument
Long-term debt, gross	1,249	1,249		1,249
Debt instrument interest rate stated percentage	4.10%	4.10%		4.10%
2.70% senior notes due 2023
Debt instrument
Long-term debt, gross	1,191	1,224		1,224
Debt instrument interest rate stated percentage	2.70%	2.70%		2.70%	2.70%
Debt instrument issued					1,250
3.125% senior notes due 2022
Debt instrument
Long-term debt, gross	813	887		887
Debt instrument interest rate stated percentage	3.125%	3.125%		3.125%
4.125% senior notes due 2016
Debt instrument
Long-term debt, gross	750	750		750
Debt instrument interest rate stated percentage	4.125%	4.125%		4.125%
2.5% senior notes due 2016
Debt instrument
Long-term debt, gross	700	700		700
Debt instrument interest rate stated percentage	2.50%	2.50%		2.50%
1.45% senior notes due 2013
Debt instrument
Debt instrument interest rate stated percentage		1.45%		1.45%
Long term debt matured				600
1.50% senior notes due 2018
Debt instrument
Long-term debt, gross	500	500		500
Debt instrument interest rate stated percentage	1.50%	1.50%		1.50%	1.50%
Debt instrument issued					500
8.45% senior notes due 2029
Debt instrument
Long-term debt, gross	116	116		116
Debt instrument interest rate stated percentage	8.45%	8.45%		8.45%
9.25% senior debentures due 2019
Debt instrument
Long-term debt, gross	116	116		116
Debt instrument interest rate stated percentage	9.25%	9.25%		9.25%
7.2% senior debentures due 2028
Debt instrument
Long-term debt, gross	82	82		82
Debt instrument interest rate stated percentage	7.20%	7.20%		7.20%
Variable rate bonds due 2030 (0.04% and 0.13% as of December 31, 2013 and 2012, respectively)
Debt instrument
Long-term debt, gross	68	68		68
8.75% medium-term notes due 2023
Debt instrument
Long-term debt, gross	22	22		22
Debt instrument interest rate stated percentage	8.75%	8.75%		8.75%
Senior notes due in 2021 and later
Debt instrument
Notes repurchased		90		90
2.70% senior notes due 2023, 1.50% senior notes due 2018
Debt instrument
Debt instrument issued					1,750
Net proceeds from issuance of long-term debt					1,740
Various Senior notes due 2022 and later
Debt instrument
Notes repurchased	107
California Resources Corporation
Debt instrument
Third party guarantees related to California Resources Corporation	$ 161

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Derivatives (Tables)

12 Months Ended

Dec. 31, 2014

Derivatives - table

Cash-flow hedges - after-tax gains and losses recognized in, and reclassified to income from, Accumulated Other Comprehensive Income (in millions)

	After-tax
As of December 31, (in millions)	2014			2013
Unrealized losses recognized in AOCI	$	(5	)	$	(3	)
Losses (Gains) reclassified to income	$	8		$	(4	)

Gross and net fair values of outstanding derivatives (in millions)

(in millions)
December 31, 2014	Asset Derivatives Balance Sheet Location	Fair Value			Liability Derivatives Balance Sheet Location	Fair Value
Cash-flow hedges (a)
Commodity contracts	Other current assets	$	—		Accrued liabilities	$	—
	Long-term receivables and other assets, net	—			Deferred credits and other liabilities	—
		$	—			$	—
Derivatives not designated as hedging instruments (a)
Commodity contracts	Other current assets	$	828		Accrued liabilities	$	886
	Long-term receivables and other assets, net	11			Deferred credits and other liabilities	110
		839				996
Total gross fair value		839				996
Less: counterparty netting and cash collateral (b) (d)		(742		)		(756		)
Total net fair value of derivatives		$	97			$	240

(in millions)

December 31, 2013	Asset Derivatives Balance Sheet Location	Fair Value			Liability Derivatives Balance Sheet Location	Fair Value
Cash-flow hedges (a)
Commodity contracts	Other current assets	$	—		Accrued liabilities	$	4
	Long-term receivables and other assets, net	—			Deferred credits and other liabilities	—
		$	—			$	4
Derivatives not designated as hedging instruments (a)
Commodity contracts	Other current assets	$	367		Accrued liabilities	$	407
	Long-term receivables and other assets, net	13			Deferred credits and other liabilities	11
		380				418
Total gross fair value		380				422
Less: counterparty netting and cash collateral (c) (d)		(329		)		(364		)
Total net fair value of derivatives		$	51			$	58

(a)	Fair values are presented at gross amounts, including when the derivatives are subject to master netting arrangements and presented on a net basis in the consolidated balance sheets.
(b)	As of December 31, 2014, collateral received of zero has been netted against derivative assets and collateral paid of $8 million has been netted against derivative liabilities.
(c)	As of December 31, 2013, collateral received of $11 million has been netted against derivative assets and collateral paid of $46 million has been netted against derivative liabilities.
(d)	Select clearinghouses and brokers require Occidental to post an initial margin deposit. Collateral, mainly for initial margin, of $44 million and $103 million as of December 31, 2014 and 2013, respectively, deposited by Occidental, has not been reflected in these derivative fair value tables. This collateral is included in other current assets in the consolidated balance sheets.

Not designated as hedging instruments | Commodity Contracts

Derivatives - table

Net volumes of outstanding commodity derivatives contracts

	Net Outstanding Position Long / (Short)
Commodity	2014		2013
Oil (million barrels)	(9	)	(22	)
Natural gas (billion cubic feet)	(32	)	(10	)
CO2 (million cubic feet)	621		—

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DOMESTIC AND FOREIGN INCOME TAXES (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Domestic and foreign components of income from continuing operations before domestic and foreign income taxes
Income from continuing operations before income taxes, Domestic	$ (732,000,000)	$ 3,399,000,000	$ 852,000,000
Income from continuing operations before income taxes, Foreign	2,273,000,000	4,747,000,000	5,636,000,000
Income from continuing operations before income taxes, Total	1,541,000,000	8,146,000,000	6,488,000,000
Provisions (credits) for domestic and foreign income taxes on continuing operations
Current United States Federal tax expense (benefit)	870,000,000	113,000,000	(308,000,000)
Current State and Local tax expense (benefit)	81,000,000	17,000,000	4,000,000
Current Foreign tax expense (benefit)	1,912,000,000	2,170,000,000	2,383,000,000
Current Total tax expense (benefit)	2,863,000,000	2,300,000,000	2,079,000,000
Deferred United States Federal tax expense (benefit)	(1,037,000,000)	883,000,000	519,000,000
Deferred State and Local tax expense (benefit)	(71,000,000)	48,000,000	20,000,000
Deferred Foreign tax expense (benefit)	(70,000,000)	(17,000,000)	41,000,000
Deferred Total tax expense (benefit)	(1,178,000,000)	914,000,000	580,000,000
United States Federal Total tax expense (benefit)	(167,000,000)	996,000,000	211,000,000
State and Local Total tax expense (benefit)	10,000,000	65,000,000	24,000,000
Foreign Total tax expense (benefit)	1,842,000,000	2,153,000,000	2,424,000,000
Total tax expense (benefit)	1,685,000,000	3,214,000,000	2,659,000,000
Reconciliation of the United States federal statutory income tax rate to Occidental's worldwide effective tax rate on income from continuing operations
United States federal statutory tax rate (as a percent)	35.00%	35.00%	35.00%
Effect of spin-off of California Resources	12.00%
Operations outside the United States (as a percent)	65.00%	5.00%	6.00%
State income taxes, net of federal benefit (as a percent)	1.00%	1.00%	1.00%
Other (as a percent)	(4.00%)	(1.00%)	(1.00%)
Worldwide effective tax rate (as a percent)	109.00%	40.00%	41.00%
Deferred Tax Assets and Liabilities
Deferred Tax Assets, environmental reserves	123,000,000	121,000,000
Deferred Tax Assets, postretirement benefit accruals	379,000,000	376,000,000
Deferred Tax Assets, deferred compensation and benefits	208,000,000	222,000,000
Deferred Tax Assets, asset retirement obligations	307,000,000	407,000,000
Deferred Tax Assets, foreign tax credit carryforwards	1,765,000,000	1,091,000,000
Deferred tax Assets, federal benefit of state income taxes	85,000,000	136,000,000
Deferred Tax Assets, all other	274,000,000	344,000,000
Deferred Tax Assets, subtotal	3,141,000,000	2,697,000,000
Deferred Tax Assets, valuation allowance	(1,744,000,000)	(1,074,000,000)
Deferred Tax Assets, total deferred taxes	1,397,000,000	1,623,000,000
Deferred Tax Liabilities, property, plant and equipment differences	4,081,000,000	8,363,000,000
Deferred Tax Liabilities, equity investments, partnerships and foreign subsidiaries		225,000,000
Deferred Tax Liabilities, all other	221,000,000	82,000,000
Deferred Tax Liabilities, Gross	4,302,000,000	8,670,000,000
Deferred Tax Liabilities, total deferred taxes	4,302,000,000	8,670,000,000
Deferred tax assets, current	110,000,000	150,000,000
Unremitted earnings of certain consolidated foreign subsidiaries	9,900,000,000
Deferred tax liability not recognized, indefinitely reinvested foreign earnings	140,000,000
Discontinued operations income tax charges (benefits)	454,000,000	550,000,000	466,000,000
Credit to additional paid-in capital, excess tax benefit from the exercise of certain stock-based compensation awards	4,000,000	6,000,000	8,000,000
Unrecognized tax benefits included in deferred credits and other liabilities - other that would affect effective tax rate	61,000,000
Reconciliation of unrecognized tax benefits
Balance, at beginning of period	61,000,000	76,000,000
Reductions based on tax positions related to prior years and settlements		(15,000,000)
Balance, at end of period	$ 61,000,000	$ 61,000,000	$ 76,000,000

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Industry Segments

12 Months Ended

Dec. 31, 2014

Industry Segments

Industry Segments

NOTE 16INDUSTRY 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 power.  Additionally, the midstream and marketing segment 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 and restricted cash, certain corporate receivables and PP&E, and an investment in the Joslyn, Canada oil sands project.

Industry Segments
(in millions)							Midstream			Corporate
							and			and
	Oil and Gas			Chemical			Marketing			Eliminations			Total
YEAR ENDED DECEMBER 31, 2014
Net sales	$	13,887	(a)	$	4,817	(b)	$	1,373	(c)	$	(765)		$	19,312
Pretax operating profit (loss)	$	428	(d)	$	420	(e)	$	2,578	(f)	$	(1,871)	(g)	$	1,555
Net income attributable to noncontrolling interest	—			—			(14)			—			(14)
Income taxes	—			—			—			(1,685)		(g)	(1,685)
Discontinued operations, net	—			—			—			760		(i)	760
Net income (loss) attributable to common stock	$	428		$	420		$	2,564		$	(2,796)		$	616
Investments in unconsolidated entities	$	11		$	202		$	948		$	10		$	1,171
Property, plant and equipment additions, net (k)	$	6,589		$	325		$	2,093		$	103		$	9,110
Depreciation, depletion and amortization	$	3,701		$	367		$	160		$	33		$	4,261
Total assets	$	31,072		$	3,917		$	12,283		$	8,987		$	56,259
YEAR ENDED DECEMBER 31, 2013
Net sales	$	15,008	(a)	$	4,673	(b)	$	1,174	(c)	$	(685)		$	20,170
Pretax operating profit (loss)	$	6,411	(d)	$	743	(e)	$	1,523	(f)	$	(531)	(g)	$	8,146
Income taxes	—			—			—			(3,214)		(h)	(3,214)
Discontinued operations, net	—			—			—			971		(i)	971
Net income (loss) attributable to common stock	$	6,411		$	743		$	1,523		$	(2,774)		$	5,903
Investments in unconsolidated entities	$	108		$	34		$	1,307		$	10		$	1,459
Property, plant and equipment additions, net (k)	$	5,456		$	435		$	1,437		$	166		$	7,494
Depreciation, depletion and amortization	$	3,676		$	346		$	149		$	32		$	4,203
Total assets	$	46,213		$	3,947		$	14,374		$	4,909		$	69,443
YEAR ENDED DECEMBER 31, 2012
Net sales	$	14,953	(a)	$	4,580	(b)	$	1,164	(c)	$	(597)		$	20,100
Pretax operating profit (loss)	$	5,840	(d)	$	720		$	440	(f)	$	(512)	(g)	$	6,488
Income taxes	—			—			—			(2,659)		(h)	(2,659)
Discontinued operations, net	—			—			—			769		(i)	769
Net income (loss) attributable to common stock	$	5,840	(d)	$	720		$	440		$	(2,402)		$	4,598
Investments in unconsolidated entities	$	113		$	108		$	1,662		$	11		$	1,894
Property, plant and equipment additions, net (k)	$	6,067		$	365		$	1,451		$	91		$	7,974
Depreciation, depletion and amortization	$	3,065		$	345		$	148		$	27		$	3,585
Total assets	$	44,004		$	3,854		$	12,762		$	3,590		$	64,210

(See footnotes on next page)

Footnotes:

(a) Oil sales represented approximately 90 percent, 91 percent and 91 percent of the oil and gas segment net sales for the years ended December 31, 2014, 2013 and 2012, respectively.

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

	Basic Chemicals	Vinyls	Other Chemicals
Year ended December 31, 2014	54%	43%	3%
Year ended December 31, 2013	55%	42%	3%
Year ended December 31, 2012	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, 2014	49%	31%	20%
Year ended December 31, 2013	54%	30%	16%
Year ended December 31, 2012	60%	24%	16%

(d) The 2014 amount includes pre-tax charges of $4.7 billion for the impairment of domestic oil and gas assets, pre-tax charges of $1.1 billion for the impairment of foreign oil and gas assets, and pre-tax gain of $531 million for the sale of the Hugoton field. The 2013 amount includes pre-tax charges of $607 million for the impairment of domestic non-producing acreage.  The 2012 amount includes pre-tax charges of $1.7 billion for the impairment of domestic gas assets and related items.

(e) The 2014 amount includes the pre-tax charge of $149 million. The 2013 amount includes a pre-tax gain of $131 million for the sale of an investment in Carbocloro.

(f) The 2014 amount includes pre-tax gains of $633 million and $1,351 million for the sales of BridgeTex Pipeline and a portion of an investment in Plains Pipeline, respectively, and other charges of $31 million. The 2013 amount includes a pre-tax gain of $1,044 million for the sale of a portion of an investment in Plains Pipeline and other items of $58 million.

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

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

(i) Relates to discontinued operations from Ecuador and the spin-off of California Resources.

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

Benefit (Charge) (in millions)	2014		2013		2012
CORPORATE
Pre-tax operating profit (loss)
California Resources other than temporary loss	$	(553)	$	—	$	—
Joslyn Impairment	(805)		—		—
Spin-off and other costs	(61)		—		—
Litigation reserves	—		—		(20)
Charge for former executives and consultants	—		(55)		—
	$	(1,419)	$	(55)	$	(20)
Income taxes
Tax effect of pre-tax and other adjustments *	$	927	$	(167)	$	612

*  Amounts represent the tax effect of the pre-tax adjustments listed in this note, as well as those in footnotes (d), (e) and (f).

(k) Includes capital expenditures and capitalized interest, but excludes acquisition and disposition of assets.

GEOGRAPHIC AREAS

(in millions)	Net sales (a)						Property, plant and equipment, net
For the years ended December 31,	2014		2013		2012		2014		2013		2012
United States	$	11,943	$	11,724	$	11,287	$	26,673	$	42,956	$	40,786
Foreign
Qatar	2,803		2,995		3,356		2,605		2,605		2,676
Oman	2,524		2,567		2,578		2,876		2,509		2,353
Colombia	938		1,022		1,027		1,396		1,259		1,041
United Arab Emirates	—		—		—		4,312		3,131		2,104
Other Foreign	1,104		1,862		1,852		1,868		3,361		3,104
Total Foreign	7,369		8,446		8,813		13,057		12,865		11,278
Total	$	19,312	$	20,170	$	20,100	$	39,730	$	55,821	$	52,064

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

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Derivatives (Details)	Dec. 31, 2013 ft3
Derivatives
Natural gas held in storage (in cubic feet)	11,000,000,000
Forecast sale of natural gas from storage designated as cash-flow hedges (in cubic feet)	13,000,000,000

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Spin-off of California Resources Corporation (Tables)

12 Months Ended

Dec. 31, 2014

Spin-off and related activities

Schedule of carrying value of major categories of assets and liabilities (in millions)

(in millions)	November 30, 2014		December 31, 2013
CURRENT ASSETS
Cash and cash equivalents	$	8	$	—
Accounts receivables, net	591		30
Inventories	73		75
Other current assets	22		125
Total current assets	694		230
Total property, plant, and equipment	23,257		21,065
Accumulated depreciation, depletion, and amortization	(8,079)		(6,974)
	15,178		14,091
LONG-TERM RECEIVABLES AND OTHER ASSETS, NET	112		35
TOTAL ASSETS	$	15,984	$	14,356
CURRENT LIABILITIES
Accounts payable	$	696	$	447
Accrued liabilities	182		253
Total current liabilities	878		700
LONG-TERM DEBT, NET	6,295		—
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred domestic and foreign income taxes	3,227		2,904
Other	531		509
	3,758		3,413
TOTAL LIABILITIES	$	10,931	$	4,113

Schedule of Sales and other operating revenue and income from discontinued operations (in millions)

For the years ended December 31, (in millions)	2014		2013		2012
Sales and other operating revenue from discontinued operations	$	3,951	$	4,285	$	4,072
Income from discontinued operations before-tax	1,205		1,531		1,265
Income tax expense	440		541		459
Income from discontinued operations	$	765	$	990	$	806

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STOCK-BASED INCENTIVE PLANS (Tables)

12 Months Ended

Dec. 31, 2014

STOCK-BASED INCENTIVE PLANS

Summary of certain stock-based incentive amounts

For the years ended December 31, (in millions)	2014		2013		2012
Compensation expense	$	129	$	152	$	78
Income tax benefit recognized in the income statement	46		55		29
Intrinsic value of options and stock-settled SARs exercised	5		24		18
Cash paid (a)	95		96		83
Fair value of RSUs and TSRIs vested during the year (b)	56		83		28

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

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

Summary of changes in Occidental's unvested cash- and stock- settled RSUs

	Cash-Settled					Stock-Settled
	RSUs (000’s)		Weighted-Average Grant-Date Fair Value			RSUs (000’s)		Weighted-Average Grant-Date Fair Value
Unvested at January 1	1,431			$	90.12	1,607			$	90.26
Granted	726			100.95		785			101.77
Vested	(641	)		92.46		(553	)		94.34
Shares issued upon California Resources spin-off	76			—		95			—
Shares forfeited by employees of California Resources	(396	)		90.70		(412	)		93.30
Forfeitures	(79	)		91.00		(97	)		92.13
Unvested at December 31	1,117			89.42		1,425			88.98

Grant-date assumptions used in the Monte Carlo simulation models for the estimated payout level of TSRIs

	TSRIs
Year Granted	2014			2013			2012
Assumptions used:
Risk-free interest rate	1.0		%	0.6		%	0.4		%
Dividend yield	2.8		%	2.8		%	2.6		%
Volatility factor	27		%	30		%	34		%
Expected life (years)	3			3			3
Grant-date fair value of underlying Occidental common stock	$	101.95		$	91.97		$	84.57

Summary of Option and SAR transactions

	Cash-Settled						Stock-Settled
	SARs (000’s)	Weighted- Average Exercise Price		Weighted- Average Remaining Contractual Term (yrs)	Aggregate Intrinsic Value (000’s)		SARs & Options (000’s)	Weighted- Average Exercise Price		Weighted- Average Remaining Contractual Term (yrs)	Aggregate Intrinsic Value (000’s)
Beginning balance, January 1	352	$	24.66				145	$	42.11
Exercised	(352)	$	24.66				(87)	$	38.00
Shares issued upon California Resources spin-off	—	$	—				3	$	47.87
Ending balance, December 31	—	$	—	—	$	—	61	$	45.78	1.3	$	2,125
Exercisable at December 31	—	$	—	—	$	—	61	$	45.78	1.3	$	2,125

TSRIs

STOCK-BASED INCENTIVE PLANS

Summary of Occidental's unvested awards

	TSRIs
	Awards (000’s)		Weighted-Average Grant-Date Fair Value of Occidental Stock
Unvested at January 1 (a)	832			$	92.49
Granted (a)	106			101.95
Vested (a)	(300	)		102.97
Forfeitures	(16	)		90.65
Shares issued upon California Resources spin-off	33			—
Shares forfeited by employees of California Resources	(82	)		87.28
Unvested at December 31 (a)	573			84.22

(a) Presented at the target or mid-point payouts.

ROCEs

STOCK-BASED INCENTIVE PLANS

Summary of Occidental's unvested awards

Table 6

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Derivatives (Details 3) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Outstanding commodity derivatives contracts not designated as hedging instruments
Net gains from derivatives not designated as hedging instruments recognized in net sales (in dollars)	$ (71)	$ 11
CO2 (in cubic feet)
Outstanding commodity derivatives contracts not designated as hedging instruments
Net Outstanding Position Long/(Short)	621,000,000
Oil (in barrels)
Outstanding commodity derivatives contracts not designated as hedging instruments
Net Outstanding Position Long/(Short)	(9,000,000)	(22,000,000)
Natural Gas (in cubic feet)
Outstanding commodity derivatives contracts not designated as hedging instruments
Net Outstanding Position Long/(Short)	(32,000,000,000)	(10,000,000,000)

XML

Spin-off of California Resources Corporation (Details 2) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
PROPERTY, PLANT, AND EQUIPMENT
Accumulated depreciation, depletion and amortization	$ 34,785,000,000	$ 33,231,000,000
Sales and other operating revenues and income from discontinued operations related to California Resources Company
Income tax expense	454,000,000	550,000,000	466,000,000
Income from discontinued operations	760,000,000	971,000,000	769,000,000
California Resources Corporation
CURRENT ASSETS
Cash and cash equivalents	8,000,000
Trade receivables, net	591,000,000	30,000,000
Inventories	73,000,000	75,000,000
Other current assets	22,000,000	125,000,000
Total current assets	694,000,000	230,000,000
PROPERTY, PLANT, AND EQUIPMENT
Total Property, Plant and Equipment	23,257,000,000	21,065,000,000
Accumulated depreciation, depletion and amortization	(8,079,000,000)	(6,974,000,000)
LONG TERM RECEIVABLES AND OTHER ASSETS, NET	112,000,000	35,000,000
TOTAL ASSETS OF DISCOUNTINUED OPERATIONS	15,984,000,000	14,356,000,000
CURRENT LIABILITIES
Accounts payable	696,000,000	447,000,000
Accrued liabilities	182,000,000	253,000,000
Total current liabilities	878,000,000	700,000,000
LONG-TERM DEBT, NET	6,295,000,000
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred domestic and foreign income taxes	3,227,000,000	2,904,000,000
Other	531,000,000	509,000,000
Total deferred credits and other liabilities	3,758,000,000	3,413,000,000
TOTAL LIABILITIES OF DISCONTINUED OPERATIONS	10,931,000,000	4,113,000,000
California Resources Corporation | Spin-off California Resources Corp
Sales and other operating revenues and income from discontinued operations related to California Resources Company
Sales and other operating revenue from discontinued operations	3,951,000,000	4,285,000,000	4,072,000,000
Income from discontinued operations before-tax	1,205,000,000	1,531,000,000	1,265,000,000
Income tax expense	440,000,000	541,000,000	459,000,000
Income from discontinued operations	$ 765,000,000	$ 990,000,000	$ 806,000,000

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Retirement and Postretirement Benefit Plans (Details 2) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Pension Benefit
Defined Benefit Plan Disclosure
Fair value of plan assets	$ 436	$ 538	$ 499
Estimated future benefit payments
2014	38
2015	37
2016	33
2017	32
2018	32
2019 - 2023	191
Expected contribution to defined benefit pension plans during 2014	6
Postretirement Benefit
Estimated future benefit payments
2014	58
2015	59
2016	59
2017	59
2018	60
2019 - 2023	304
Debt securities
Defined Benefit Plan Disclosure
Target allocation of plan assets (as a percent)	35.00%
Pension Plan Assets - Gross | Pension Benefit
Defined Benefit Plan Disclosure
Fair value of plan assets	449	543
U.S. government securities | Pension Benefit
Defined Benefit Plan Disclosure
Fair value of plan assets	15	16
Common and preferred stocks
Defined Benefit Plan Disclosure
Target allocation of plan assets (as a percent)	65.00%
Common and preferred stocks | Pension Benefit
Defined Benefit Plan Disclosure
Fair value of plan assets	196	201
Corporate bonds | Pension Benefit
Defined Benefit Plan Disclosure
Fair value of plan assets	76	84
Common/collective trusts | Pension Benefit
Defined Benefit Plan Disclosure
Fair value of plan assets	13	19
Bond funds | Pension Benefit
Defined Benefit Plan Disclosure
Fair value of plan assets	42	64
Blend funds | Pension Benefit
Defined Benefit Plan Disclosure
Fair value of plan assets	68	105
Value and growth funds | Pension Benefit
Defined Benefit Plan Disclosure
Fair value of plan assets		6
Other | Pension Benefit
Defined Benefit Plan Disclosure
Fair value of plan assets	39	48
Net Payables | Pension Benefit
Defined Benefit Plan Disclosure
Fair value of plan assets	13	5
Level 1 | Pension Plan Assets - Gross | Pension Benefit
Defined Benefit Plan Disclosure
Fair value of plan assets	321	392
Level 1 | U.S. government securities | Pension Benefit
Defined Benefit Plan Disclosure
Fair value of plan assets	15	16
Level 1 | Common and preferred stocks | Pension Benefit
Defined Benefit Plan Disclosure
Fair value of plan assets	196	201
Level 1 | Bond funds | Pension Benefit
Defined Benefit Plan Disclosure
Fair value of plan assets	42	64
Level 1 | Blend funds | Pension Benefit
Defined Benefit Plan Disclosure
Fair value of plan assets	68	105
Level 1 | Value and growth funds | Pension Benefit
Defined Benefit Plan Disclosure
Fair value of plan assets		6
Level 2 | Pension Plan Assets - Gross | Pension Benefit
Defined Benefit Plan Disclosure
Fair value of plan assets	127	140
Level 2 | Corporate bonds | Pension Benefit
Defined Benefit Plan Disclosure
Fair value of plan assets	76	84
Level 2 | Common/collective trusts | Pension Benefit
Defined Benefit Plan Disclosure
Fair value of plan assets	13	19
Level 2 | Other | Pension Benefit
Defined Benefit Plan Disclosure
Fair value of plan assets	38	37
Level 3 | Pension Plan Assets - Gross | Pension Benefit
Defined Benefit Plan Disclosure
Fair value of plan assets	1	11
Level 3 | Other | Pension Benefit
Defined Benefit Plan Disclosure
Fair value of plan assets	$ 1	$ 11

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LONG-TERM DEBT (Details 2) (Credit Facility, USD $) In Billions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014
Credit Facility
Debt instrument
Credit Facility, maximum borrowing capacity	$ 2.0
Average annual facility fee as percent of the total commitment amounts	0.07%
Maximum amount of credit facility available in the form of letters of credit	$ 1.0

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CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
CASH FLOW FROM OPERATING ACTIVITIES
Net income	$ 630	$ 5,903	$ 4,598
Adjustments to reconcile net income to net cash provided by operating activities:
Discontinued operations, net	(760)	(971)	(769)
Depreciation, depletion and amortization of assets	4,261	4,203	3,585
Deferred income tax provision	(1,178)	914	580
Other noncash charges to income	115	271	167
Asset impairments and related items	7,379	621	1,710
Gain on sale of equity investments	(2,505)	(1,175)
Undistributed earnings from equity investments	38	(3)	(30)
Dry hole expenses	99	70	151
Changes in operating assets and liabilities:
Decrease (increase) in receivables	1,413	(747)	452
(Increase) decrease in inventories	(112)	79	(242)
Decrease in other current assets	89	58	176
(Decrease) increase in accounts payable and accrued liabilities	(544)	255	(959)
(Decrease) increase in current domestic and foreign income taxes	(54)	369	1
Other operating, net		382	(370)
Operating cash flow from continuing operations	8,871	10,229	9,050
Operating cash flow from discontinued operations, net of taxes	2,197	2,549	2,249
Net cash provided by operating activities	11,068	12,778	11,299
CASH FLOW FROM INVESTING ACTIVITIES
Capital expenditures	(8,930)	(7,357)	(7,874)
Change in capital accrual	542	149	13
Payments for purchases of assets and businesses	(1,687)	(606)	(2,084)
Sales of equity investments and assets, net	4,177	1,619	4
Other, net	(346)	(122)	78
Investing cash flow from continuing operations	(6,244)	(6,317)	(9,863)
Investing cash flow from discontinued operations	(2,226)	(1,727)	(2,779)
Net cash used by investing activities	(8,470)	(8,044)	(12,642)
CASH FLOW FROM FINANCING ACTIVITIES
Change in restricted cash	4,019
Special cash distributions from California Resources Corporation	6,100
Purchases of long-term debt	(107)	(690)
Proceeds from long-term debt			1,736
Proceeds from issuance of common stock	33	30	85
Purchases of treasury stock	(2,500)	(943)	(583)
Contributions from noncontrolling interest	375	214	32
Cash dividends paid	(2,210)	(1,553)	(2,128)
Other, net	2	9	12
Financing cash flow from continuing operations	(2,326)	(2,933)	(846)
Financing cash flow from discontinued operations	124
Net cash (used) provided by financing activities	(2,202)	(2,933)	(846)
(Decrease) increase in cash and cash equivalents	396	1,801	(2,189)
Cash and cash equivalents-beginning of period	3,393	1,592	3,781
Cash and cash equivalents-end of period	$ 3,789	$ 3,393	$ 1,592

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INVESTMENTS AND RELATED-PARTY TRANSACTIONS (Details) (USD $) Share data in Millions, unless otherwise specified	1 Months Ended		12 Months Ended
	Oct. 31, 2014	Oct. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
EQUITY INVESTMENTS
Pre-tax gain on sale of equity investment			2,505,000,000	1,175,000,000
RELATED-PARTY TRANSACTIONS
Sales to related parties			835,000,000	663,000,000	419,000,000
Purchases from related parties			6,000,000		8,000,000
Services to related parties			27,000,000	30,000,000	17,000,000
Advances and amounts due from related parties			26,000,000	67,000,000	25,000,000
Amounts due to related parties			15,000,000	3,000,000	129,000,000
Equity Method Investments
Equity method investment amounts			1,171,000,000	1,459,000,000	1,894,000,000
Equity investments dividends paid			396,000,000	447,000,000	526,000,000
Excess of investments in equity investees over the underlying equity in net assets			632,000,000
Excess of investments in equity investees over the underlying equity in net assets, which represents goodwill			546,000,000
Equity-method investments financial information summarized by Income Statement line item
Revenues			3,090,000,000	3,373,000,000	2,667,000,000
Costs and expenses			2,774,000,000	2,987,000,000	2,310,000,000
Net income			316,000,000	386,000,000	357,000,000
Equity-method investments financial information summarized by Balance Sheet line item
Current assets			1,127,000,000	1,813,000,000
Non-current assets			2,925,000,000	4,412,000,000
Current liabilities			771,000,000	1,308,000,000
Long-term debt			1,701,000,000	2,506,000,000
Other non-current liabilities			83,000,000	163,000,000
Stockholders' equity			1,498,000,000	2,248,000,000
General Partner of Plains All American Pipeline,L.P
EQUITY INVESTMENTS
Ownership interest (as a percent)			13.00%
Proceeds from sale of investment	1,700,000,000	1,400,000,000
Pre-tax gain on sale of equity investment	1,400,000,000	1,000,000,000
RELATED-PARTY TRANSACTIONS
Sales to related party (as a percent)			46.00%	72.00%	80.00%
California Resource Corporation
EQUITY INVESTMENTS
Investment recorded as available for sale asset, shares owned			71.5
Interest in investment recorded as available for sale asset (as a percent)			18.70%
Value of investment recorded as available for sale asset			394,000,000
Other than temperary loss			553,000,000
Dolphin Energy
EQUITY INVESTMENTS
Equity method investment ownership percentage			24.50%
Ownership interest (as a percent)			24.50%
Number of separate economic interests comprising investment in unconsolidated affiliate			2

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
RISKS AND UNCERTAINTIES
Assets, relating to operations in countries outside North America	$ 15,000,000,000
Net sales, relating to operations in countries outside North America	7,300,000,000
CASH AND CASH EQUIVALENTS
Total cash equivalents	3,400,000,000	2,900,000,000
RESTRICTED CASH
Restricted cash	4,019,000,000
Restricted cash useage term (in months)	18 months
PROPERTY, PLANT AND EQUIPMENT
Maximum time period after which costs of exploratory wells are charged to expense if determination of proved reserves has not been made	12 months	12 months	12 months
Net capitalized costs attributable to unproved properties	2,000,000,000
Capitalized exploratory well costs for the years ended December 31:
Balance - Beginning of Year	140,000,000	124,000,000	189,000,000
Additions to capitalized exploratory well costs pending the determination of proved reserves	462,000,000	337,000,000	400,000,000
Reclassifications to property, plant and equipment based on the determination of proved reserves	(423,000,000)	(271,000,000)	(389,000,000)
Spin-off of California Resources	(17,000,000)
Capitalized exploratory well costs charged to expense	(21,000,000)	(50,000,000)	(76,000,000)
Balance - End of Year	141,000,000	140,000,000	124,000,000
ACCRUED LIABILITIES-CURRENT
Accrued liabilities for accrued payroll, commissions and related expenses	361,000,000	459,000,000
ENVIRONMENTAL LIABILITIES AND EXPENDITURES
Minimum period of investigation and cleanup for Comprehensive Environmental Response, Compensation and Liability Act National Priorities List sites	10 years	10 years	10 years
ASSET RETIREMENT OBLIGATIONS
Asset retirement obligation, included in deferred credits and other liabilities-other	1,024,000,000	1,283,000,000
For the years ended December 31
Beginning balance	1,332,000,000	1,266,000,000
Liabilities incurred - capitalized to PP&E	57,000,000	101,000,000
Liabilities settled and paid	(78,000,000)	(72,000,000)
Accretion expense	69,000,000	68,000,000
Acquisitions, dispositions and other - changes in PP&E	(11,000,000)	(10,000,000)
Spin-off of California Resources	(399,000,000)
Revisions to estimated cash flows - changes in PP&E	121,000,000	(21,000,000)
Ending balance	1,091,000,000	1,332,000,000	1,266,000,000
SUPPLEMENTAL CASH FLOW INFORMATION
Interest Paid	219,000,000	238,000,000	190,000,000
Capitalized interest	180,000,000	137,000,000	100,000,000
Low end of range
Summary of significant accounting policies
The estimated useful lives of Occidental's chemical assets	3 years
DERIVATIVE INSTRUMENTS
Range used to determine if derivative instrument is effective	80.00%
High end of range
Summary of significant accounting policies
The estimated useful lives of Occidental's chemical assets	50 years
DERIVATIVE INSTRUMENTS
Range used to determine if derivative instrument is effective	125.00%
Continuing operations
SUPPLEMENTAL CASH FLOW INFORMATION
United States federal, state and foreign income taxes paid for continuing operations	2,900,000,000	1,800,000,000	2,300,000,000
Production, property and other taxes paid	$ 610,000,000	$ 606,000,000	$ 524,000,000

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)

12 Months Ended

Dec. 31, 2014

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Summary of the activity of capitalized exploratory well costs for continuing operations

in millions	2014			2013			2012
Balance — Beginning of Year	$	140		$	124		$	189
Additions to capitalized exploratory well costs pending the determination of proved reserves	462			337			400
Reclassifications to property, plant and equipment based on the determination of proved reserves	(423		)	(271		)	(389		)
Spin-off of California Resources	(17		)	—			—
Capitalized exploratory well costs charged to expense	(21		)	(50		)	(76		)
Balance — End of Year	$	141		$	140		$	124

Summary of the activity of the asset retirement obligation

For the years ended December 31, (in millions)	2014			2013
Beginning balance	$	1,332		$	1,266
Liabilities incurred – capitalized to PP&E	57			101
Liabilities settled and paid	(78		)	(72		)
Accretion expense	69			68
Acquisitions, dispositions and other – changes in PP&E	(11		)	(10		)
Spin-off of California Resources	(399		)	—
Revisions to estimated cash flows – changes in PP&E	121			(21		)
Ending balance	$	1,091		$	1,332

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

12 Months Ended

Dec. 31, 2014

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Consolidation policy

PRINCIPLES OF CONSOLIDATION

The consolidated financial statements have been prepared in conformity with United States generally accepted accounting principles (GAAP) and include the accounts of OPC, its subsidiaries and its undivided interests in oil and gas exploration and production ventures.  Occidental accounts for its share of oil and gas exploration and production ventures, in which it has a direct working interest, by reporting its proportionate share of assets, liabilities, revenues, costs and cash flows within the relevant lines on the balance sheets, income statements and cash flow statements.

Certain financial statements, notes and supplementary data for prior years have been reclassified to conform to the 2014 presentation.

As a result of the spin-off of California Resources Corporation (California Resources) the statements of income and cash flows related to California Resources have been treated as discontinued operations for the years ended December 31, 2014, 2013 and 2012. The assets and liabilities of California Resources were removed from Occidental’s consolidated balance sheet as of November 30, 2014.  See Note 17 Spin-off of California Resources for additional information.

Investments in unconsolidated entities policy

INVESTMENTS IN UNCONSOLIDATED ENTITIES

Occidental’s percentage interest in the underlying net assets of affiliates as to which it exercises significant influence without having a controlling interest (excluding oil and gas ventures in which Occidental holds an undivided interest) are accounted for under the equity method.  Occidental reviews equity-method investments for impairment whenever events or changes in circumstances indicate that an other-than-temporary decline in value may have occurred.  The amount of impairment, if any, is based on quoted market prices, when available, or other valuation techniques, including discounted cash flows.

Revenue recognition policy

REVENUE RECOGNITION

Revenue is recognized from oil and gas production when title has passed to the customer, which occurs when the product is shipped.  In international locations where oil is shipped by tanker, title passes when the tanker is loaded or product is received by the customer, depending on the shipping terms.  This process occasionally causes a difference between actual production in a reporting period and sales volumes that have been recognized as revenue. Revenues from the production of oil and gas properties in which Occidental has an interest with other producers are recognized on the basis of Occidental’s net revenue interest.

Revenue from chemical product sales is recognized when the product is shipped and title has passed to the customer.  Certain incentive programs may provide for payments or credits to be made to customers based on the volume of product purchased over a defined period.  Total customer incentive payments over a given period are estimated and recorded as a reduction to revenue ratably over the contract period.  Such estimates are evaluated and revised as warranted.

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

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

Deferred tax asset valuation allowance policy

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 expected outcomes as well as 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.  Management believes that these estimates and judgments provide a reasonable basis for the fair presentation of Occidental’s financial statements. Occidental establishes a valuation allowance against net operating losses and other deferred tax assets to the extent it believes the future benefit from these assets will not be realized in the statutory carryforward periods.  Realization of deferred tax assets, including any net operating loss carryforwards, is dependent upon Occidental generating sufficient future taxable income and reversal of temporary differences in jurisdictions where such assets originate.

The accompanying consolidated financial statements include assets of approximately $15 billion as of December 31, 2014, and net sales of approximately $7.3 billion for the year ended December 31, 2014, relating to Occidental’s operations in countries outside North America.  Occidental operates some of its oil and gas business in countries that have experienced political instability, nationalizations, corruption, 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 policy

CASH AND CASH EQUIVALENTS

Cash equivalents are short-term, highly liquid investments that are readily convertible to cash.  Cash equivalents were approximately $3.4 billion and $2.9 billion at December 31, 2014 and 2013, respectively.

Restricted cash policy

RESTRICTED CASH

Restricted cash is the result of the separation of California Resources. As of December 31, 2014, there was $4.0 billion of cash restricted for the payment of dividends, payment of debt or share repurchases. Restricted cash must be used within 18 months of the date of distribution.

Available-for-sale securities and trading securities policy

INVESTMENTS

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

A decline in market value of any available-for-sale securities below cost that is deemed to be other-than-temporary results in an impairment to reduce the carrying amount to fair value.  To determine whether an impairment is other-than-temporary, Occidental considers all available information relevant to the investment, including past events and current conditions. Evidence considered in this assessment includes the reasons for the impairment, the severity and duration of the impairment, changes in value subsequent to year-end, and the general market condition in the geographic area or industry the investee operates in.

Inventory policy

INVENTORIES

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

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

Property, plant and equipment policy

PROPERTY, PLANT AND EQUIPMENT

Oil and Gas

The carrying value of Occidental’s property, plant and equipment (PP&E) represents the cost incurred to acquire or develop the asset, including any asset retirement obligations and capitalized interest, net of accumulated depreciation, depletion and amortization (DD&A) and 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	2014			2013			2012
Balance — Beginning of Year	$	140		$	124		$	189
Additions to capitalized exploratory well costs pending the determination of proved reserves	462			337			400
Reclassifications to property, plant and equipment based on the determination of proved reserves	(423		)	(271		)	(389		)
Spin-off of California Resources	(17		)	—			—
Capitalized exploratory well costs charged to expense	(21		)	(50		)	(76		)
Balance — End of Year	$	141		$	140		$	124

Occidental expenses annual lease rentals, the costs of injectants used in production and geological, geophysical and seismic costs as incurred.

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 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.

Occidental performs impairment tests with respect to its proved properties whenever events or circumstances indicate that the carrying value of property may not be recoverable. If there is an indication the carrying amount of the asset may not be recovered due to declines in current and forward prices, significant changes in reserve estimates, changes in management’s plans, or other significant events, management will evaluate the property for impairment. Under the successful efforts method, if the sum of the undiscounted cash flows is less than the carrying value of the proved property, the carrying value is reduced to estimated fair value and reported as an impairment charge in the period. Individual proved properties are grouped for impairment purposes at the lowest level for which there are identifiable cash flows, which is generally on a field by field basis.  The fair value of impaired assets is typically determined based on the present value of expected future cash flows using discount rates believed to be consistent with those used by market participants.  The impairment test incorporates a number of assumptions involving expectations of future cash flows which can change significantly over time.  These assumptions include estimates of future product prices, contractual prices, estimates of risk-adjusted proved oil and gas reserves and estimates of future operating and development costs.  See Note 15 for further discussion of asset impairments.

A portion of the carrying value of Occidental’s oil and gas properties is attributable to unproved properties.  At December 31, 2014, the net capitalized costs attributable to unproved properties were $2.0 billion.  The unproved amounts are not subject to DD&A until they are classified as proved properties. Capitalized costs attributable to the properties become subject to DD&A when proved reserves are assigned to the property.  If the exploration efforts are unsuccessful, or management decides not to pursue development of these properties as a result of lower commodity prices, higher development and operating costs, contractual conditions or other factors, 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.

Chemical

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

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

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

Midstream and Marketing

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

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

Fair value policy

FAIR VALUE MEASUREMENTS

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

Fair Values - Recurring

Occidental primarily applies the market approach for recurring fair value measurements, maximizes its use of observable inputs and minimizes its use of unobservable inputs.  Occidental utilizes the mid-point 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:

· 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 classified as Level 2 and 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 values 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 generally unobservable in the marketplace, or are observable but have been adjusted based upon various assumptions 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 policy

ACCRUED LIABILITIES—CURRENT

Accrued liabilities include accrued payroll, commissions and related expenses of $361 million and $459 million at December 31, 2014 and 2013, respectively.

Environmental liabilities and expenditures policy

ENVIRONMENTAL LIABILITIES AND EXPENDITURES

Environmental expenditures that relate to current operations are expensed or capitalized as appropriate.  Occidental records environmental reserves and related charges and expenses 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, 2014, 2013 and 2012, 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 may occur.

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

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

Asset retirement obligations policy

ASSET RETIREMENT OBLIGATIONS

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

At a certain number of its facilities, Occidental has identified conditional asset retirement obligations that are related mainly to plant decommissioning.  Occidental does not know or cannot estimate when it may settle these obligations.  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 $1,024 million and $1,283 million is included in deferred credits and other liabilities - other, with the remaining current portion in accrued liabilities at December 31, 2014 and 2013, respectively.

For the years ended December 31, (in millions)	2014			2013
Beginning balance	$	1,332		$	1,266
Liabilities incurred – capitalized to PP&E	57			101
Liabilities settled and paid	(78		)	(72		)
Accretion expense	69			68
Acquisitions, dispositions and other – changes in PP&E	(11		)	(10		)
Spin-off of California Resources	(399		)	—
Revisions to estimated cash flows – changes in PP&E	121			(21		)
Ending balance	$	1,091		$	1,332

Derivatives Policy

DERIVATIVE INSTRUMENTS

Derivatives are carried at fair value and on a net basis when a legal right of offset exists with the same counterparty.  Occidental applies hedge accounting when transactions meet specified criteria for cash-flow hedge treatment and management elects and documents such treatment.  Otherwise, any fair value gains or losses are recognized in earnings in the current period.  For cash-flow hedges, the gain or loss on the effective portion of the derivative is reported as a component of other comprehensive income (OCI) with an offsetting adjustment to the basis of the item being hedged.  Realized gains or losses from cash-flow hedges, and any ineffective portion, are recorded as a component of net sales in the consolidated statements of income.  Ineffectiveness is primarily created by a lack of correlation between the hedged item and the hedging instrument due to location, quality, grade or changes in the expected quantity of the hedged item.  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, 2014, 2013 and 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.

Stock-based incentive plans policy

STOCK-BASED INCENTIVE PLANS

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

For cash- and stock-settled restricted stock units or incentive award shares (RSUs) and capital employed incentive awards and return on assets (ROCEI/ROAI), compensation value is initially measured on the grant date using the quoted market price of Occidental’s common stock and the estimated payout at the grant date. For total shareholder return incentives (TSRIs), compensation value is initially measured on the grant date using estimated payout levels derived from a Monte Carlo valuation model.  Compensation expense for RSUs, ROCEI/ROAI 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 dividends accrued on unvested awards is adjusted quarterly for any changes in stock price and the number of share equivalents expected to be paid based on the relevant performance and market criteria, if applicable.  All such performance or stock-price-related changes are recognized in periodic compensation expense.  The stock-settled portion of these awards is expensed using the initially measured compensation value.

Earnings per share policy

EARNINGS PER SHARE

Occidental’s instruments containing rights to nonforfeitable dividends granted in stock-based awards are considered participating securities prior to vesting and, therefore, have been deducted from earnings 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 policy

RETIREMENT AND POSTRETIREMENT BENEFIT PLANS

Occidental recognizes the overfunded or underfunded amounts of its defined benefit pension and postretirement plans, which are more fully described in Note 13, 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 any 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.

Foreign currency transactions policy

FOREIGN CURRENCY TRANSACTIONS

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

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Lawsuits, Claims, Commitments and Contingencies (Details) (USD $)	12 Months Ended
	Dec. 31, 2014
Purchase obligations
State of New Jersey	State of New Jersey
Litigation Settlement, Amount	$ 190,000,000
Long term purchase and contractual obligations
Purchase obligations
Total purchase obligations	10,000,000,000
Purchase obligations, due in fiscal year 2015	3,300,000,000
Purchase obligations, due in fiscal year 2016	1,700,000,000
Purchase obligations, due in fiscal year 2017	1,000,000,000
Purchase obligations, due in fiscal year 2018	700,000,000
Purchase obligations, due in fiscal year 2019	500,000,000
Capital Additions
Purchase obligations
Commitments for major fixed and determinable capital expenditures during 2014 and thereafter	$ 1,400,000,000

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Asset Acquisitions, Dispositions and Other (Details) (USD $)	0 Months Ended	12 Months Ended		1 Months Ended	12 Months Ended	1 Months Ended			0 Months Ended	1 Months Ended
	May 15, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2014 acre	Dec. 31, 2012	May 31, 2013	Nov. 30, 2014	Oct. 31, 2013	Nov. 30, 2014	Apr. 30, 2014	Feb. 28, 2014
Acquistions, dispositions and other transactions
Gain on sale of assets and equity investments		$ 2,505,000,000	$ 1,175,000,000
Total portion of construction costs			23,000,000
Charge for former employees and consultants	55,000,000
Spin-off California Resources Corp
Acquistions, dispositions and other transactions
Percentage of common stock distributed							81.30%		81.30%
Permian region
Acquistions, dispositions and other transactions
Cash paid on acquisition		1,300,000,000		1,300,000,000
Number of acres acquired				100,000
Acquisition of oil and gas properties					1,900,000,000
Domestic Oil and Gas Properties
Acquistions, dispositions and other transactions
Acquisition of oil and gas properties			500,000,000
Brazilian chemical facility
Acquistions, dispositions and other transactions
Pre-tax proceeds from sale of assets						270,000,000
Gain on sale of assets and equity investments						131,000,000
General Partner of Plains All American Pipeline,L.P
Acquistions, dispositions and other transactions
Sale of equity investment							1,700,000,000	1,400,000,000
Gain on sale of assets and equity investments							1,400,000,000	1,000,000,000
Ingleside
Acquistions, dispositions and other transactions
Ethylene production capacity of ethane steam cracking unit, per year (in pounds)								1,200,000,000
BridgeTex
Acquistions, dispositions and other transactions
Number of transactions involved in sale							2
Sale of equity investment							1,075,000,000		75,000,000
Gain on sale of assets and equity investments		633,000,000							633,000,000
Hugoton Field operations
Acquistions, dispositions and other transactions
Pre-tax proceeds from sale of assets										1,300,000,000	1,400,000,000
Pre-tax gain on sale		$ 531,000,000								$ 531,000,000

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Inventories (Tables)

12 Months Ended

Dec. 31, 2014

Inventories

Inventories (in millions)

Balance at December 31, (in millions)	2014			2013
Raw materials	$	71		$	74
Materials and supplies	585			628
Finished goods	485			589
	1,141			1,291
Revaluation to LIFO	(89		)	(91		)
Total	$	1,052		$	1,200

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LONG-TERM DEBT (Tables)

12 Months Ended

Dec. 31, 2014

LONG-TERM DEBT

Long-term debt

Balance at December 31, (in millions)	2014			2013
1.75% senior notes due 2017	$	1,250		$	1,250
4.10% senior notes due 2021	1,249			1,249
2.70% senior notes due 2023	1,191			1,224
3.125% senior notes due 2022	813			887
4.125% senior notes due 2016	750			750
2.5% senior notes due 2016	700			700
1.50% senior notes due 2018	500			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 (0.04% as of December 31, 2014 and 2013)	68			68
8.75% medium-term notes due 2023	22			22
	6,857			6,964
Less:
Unamortized discount, net	(19		)	(25		)
Current maturities	—			—
Total	$	6,838		$	6,939

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Consolidated Statements of Stockholders' Equity (USD $) In Millions, unless otherwise specified	Common Stock	Treasury Stock	Additional Paid-in Capital	Retained Earnings	Accumulated Other Comprehensive Income (Loss)	Noncontrolling Interest	Total
Balance at Dec. 31, 2011	$ 177	$ (4,502)	$ 7,286	$ 35,142	$ (483)		$ 37,620
Increase (Decrease) in Stockholders' Equity
Net income				4,598			4,598
Other comprehensive income (loss), net of taxes					(19)		(19)
Dividends on common stock				(1,750)			(1,750)
Issuance of common stock and other, net	1		155				156
Noncontrolling interest contributions						32	32
Purchases of treasury stock		(589)					(589)
Balance at Dec. 31, 2012	178	(5,091)	7,441	37,990	(502)	32	40,048
Increase (Decrease) in Stockholders' Equity
Net income				5,903			5,903
Other comprehensive income (loss), net of taxes					199		199
Dividends on common stock				(2,062)			(2,062)
Issuance of common stock and other, net			74				74
Noncontrolling interest contributions						214	214
Purchases of treasury stock		(1,004)					(1,004)
Balance at Dec. 31, 2013	178	(6,095)	7,515	41,831	(303)	246	43,372
Increase (Decrease) in Stockholders' Equity
Net income				616			616
Other comprehensive income (loss), net of taxes					(76)		(76)
Dividends on common stock				(2,252)			(2,252)
Issuance of common stock and other, net			84				84
Noncontrolling interest distributions, net						(246)	(246)
Distribution of California Resources stock to shareholders				(4,128)	22		(4,106)
Purchases of treasury stock		(2,433)					(2,433)
Balance at Dec. 31, 2014	$ 178	$ (8,528)	$ 7,599	$ 36,067	$ (357)		$ 34,959

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LEASE COMMITMENTS (Tables)

12 Months Ended

Dec. 31, 2014

LEASE COMMITMENTS

Future net minimum lease payments for noncancelable operating leases

(in millions)	Amount
2015	$	192
2016	169
2017	161
2018	168
2019	104
Thereafter	592
Total minimum lease payments	$	1,386

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Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2014

Fair Value Measurements

Assets and liabilities measured at fair value on a recurring basis (in millions)

(in millions)	Fair Value Measurements at December 31, 2014 Using
							Netting and		Total
Description	Level 1		Level 2		Level 3		Collateral		Fair Value
Assets:
Commodity derivatives	$	712	$	127	$	—	$	(742)	$	97
Available for sale investment	$	394	$	—	$	—	$	—	$	394
Liabilities:
Commodity derivatives	$	750	$	246	$	—	$	(756)	$	240

(in millions)	Fair Value Measurements at December 31, 2013 Using
							Netting and		Total
Description	Level 1		Level 2		Level 3		Collateral		Fair Value
Assets:
Commodity derivatives	$	185	$	195	$	—	$	(329)	$	51
Liabilities:
Commodity derivatives	$	199	$	223	$	—	$	(364)	$	58

Pre-tax charges related to the impairments

(in millions)	Fair Value Measurements at December 31, 2014 Using								Total Pre-tax
							Net		(Non-cash)
Description	Level 1		Level 2		Level 3		Book Value (a)		Impairment Loss
Assets:
Impaired proved oil and gas assets - domestic	$	—	$	—	$	2,249	$	5,008	$	2,759
Impaired proved oil and gas assets - international	$	—	$	—	$	45	$	1,084	$	1,039
Impaired Chemical property, plant, and equipment	$	—	$	—	$	18	$	129	$	111

(a) Amount represents net book value at date of assessment.

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Derivatives (Details 4) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Gross and net fair values of outstanding derivatives (in millions)
Less: counterparty netting and cash collateral, asset	$ (742)	$ (329)
Less: counterparty netting and cash collateral, liability	(756)	(364)
Total net fair value, asset	97	51
Total net fair value, liability	240	58
Collateral received netted against derivative assets	0	11
Collateral paid netted against derivative liabilities	8	46
Collateral deposited with clearinghouses and brokers	44	103
Credit risk contingent features
Net derivative liabilities with credit-risk-contingent features	4	8
Amount of collateral posted	3	23
Commodity Contracts
Gross and net fair values of outstanding derivatives (in millions)
Commodity contract derivative asset, gross	839	380
Commodity contract derivative liability, gross	996	422
Cash-flow hedges | Commodity Contracts
Gross and net fair values of outstanding derivatives (in millions)
Commodity contract derivative liability, gross		4
Cash-flow hedges | Commodity Contracts | Accrued liabilities
Gross and net fair values of outstanding derivatives (in millions)
Commodity contract derivative liability, gross		4
Not designated as hedging instruments | Commodity Contracts
Gross and net fair values of outstanding derivatives (in millions)
Commodity contract derivative asset, gross	839	380
Commodity contract derivative liability, gross	996	418
Not designated as hedging instruments | Commodity Contracts | Other current assets
Gross and net fair values of outstanding derivatives (in millions)
Commodity contract derivative asset, gross	828	367
Not designated as hedging instruments | Commodity Contracts | Long-term receivables and other assets, net
Gross and net fair values of outstanding derivatives (in millions)
Commodity contract derivative asset, gross	11	13
Not designated as hedging instruments | Commodity Contracts | Accrued liabilities
Gross and net fair values of outstanding derivatives (in millions)
Commodity contract derivative liability, gross	886	407
Not designated as hedging instruments | Commodity Contracts | Deferred credits and other liabilities
Gross and net fair values of outstanding derivatives (in millions)
Commodity contract derivative liability, gross	$ 110	$ 11

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CONSOLIDATED CONDENSED BALANCE SHEETS (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
CURRENT ASSETS
Cash and cash equivalents	$ 3,789	$ 3,393
Restricted cash	4,019
Trade receivables, net of reserves of $17 in 2014 and $17 in 2013	4,206	5,674
Inventories	1,052	1,200
Other current assets	807	1,056
Total current assets	13,873	11,323
Investments
Investments in unconsolidated entities	1,171	1,459
Available for sale investment	394
Total investments	1,565	1,459
PROPERTY, PLANT AND EQUIPMENT
Oil and gas segment	59,061	72,367
Chemical segment	6,574	6,446
Midstream, marketing and other segment	8,304	8,684
Corporate	576	1,555
GROSS PROPERTY, PLANT AND EQUIPMENT	74,515	89,052
Accumulated depreciation, depletion and amortization	(34,785)	(33,231)
TOTAL PROPERTY, PLANT AND EQUIPMENT	39,730	55,821
LONG-TERM RECEIVABLES AND OTHER ASSETS, NET	1,091	840
TOTAL ASSETS	56,259	69,443
CURRENT LIABILITIES
Accounts payable	5,229	5,520
Accrued liabilities	2,601	2,556
Domestic and foreign income taxes	414	358
Total current liabilities	8,244	8,434
LONG-TERM DEBT, NET	6,838	6,939
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred domestic and foreign income taxes	3,015	7,197
Other	3,203	3,501
Total deferred credits and other liabilities	6,218	10,698
CONTINGENT LIABILITIES AND COMMITMENTS
STOCKHOLDERS' EQUITY
Common stock, $0.20 per share par value, authorized shares: 1.1 billion, outstanding shares: 2014 - 890,557,537 and 2013 - 889,919,058	178	178
Treasury stock: 2014 - 119,951,199 shares and 2013 - 93,928,179 shares	(8,528)	(6,095)
Additional paid-in capital	7,599	7,515
Retained earnings	36,067	41,831
Accumulated other comprehensive loss	(357)	(303)
Total equity attributable to common stock	34,959	43,126
Noncontrolling interest		246
Total stockholders' equity	34,959	43,372
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$ 56,259	$ 69,443

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Inventories (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Inventories
Net carrying values of inventories valued under the LIFO method	$ 199	$ 205
Raw materials	71	74
Materials and supplies	585	628
Finished goods	485	589
Inventories, Gross	1,141	1,291
LIFO reserve	(89)	(91)
Total	$ 1,052	$ 1,200

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CONSOLIDATED CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
CONSOLIDATED CONDENSED STATEMENTS OF COMPREHENSIVE INCOME
Net income attributable to common stock	$ 616		$ 5,903		$ 4,598
Other comprehensive income items:
Foreign currency translation (losses) gains	(2)		2		(25)
Realized foreign currency translation losses			28
Unrealized losses on derivatives	(5)	[1]	(3)	[1]	16	[1]
Pension and postretirement (losses) gains	(77)	[2]	176	[2]	14	[2]
Distribution of California Resources stock to shareholders	22	[3]
Reclassification to income of realized losses (gains) on derivatives	8	[4]	(4)	[4]	(24)	[4]
Other comprehensive income, net of tax	(54)	[5]	199	[5]	(19)	[5]
Comprehensive income attributable to common stock	$ 562		$ 6,102		$ 4,579

[1] Net of tax of $3, $2 and $(9) in 2014, 2013 and 2012, respectively.

[2] Net of tax of $44, $(101) and $(8) in 2014, 2013 and 2012, respectively. See Note 13, Retirement and Postretirement Benefit Plans, for additional information.

[3] Net of tax of $(14) in 2014.

[4] Net of tax of $(5), $2 and $14 in 2014, 2013 and 2012, respectively.

[5] There were no other comprehensive income (loss) items related to noncontrolling interests in 2014, 2013 and 2012.

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STOCK-BASED INCENTIVE PLANS (Details) (USD $)	12 Months Ended
	Dec. 31, 2014 item	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Share-based Compensation Arrangement by Share-based Payment Award
Aggregate number of shares authorized for issuance	66,000,000
Cumulative shares issued since inception of the plan	17,000,000
Maximum shares available for future issuance	20,000,000
Number of shares counted for each share covered by an award in determining the number of shares that are available for future awards	3
Number of times, as applicable, shares available for future awards may increase by shares that fail to vest, or are forfeited or canceled, or correspond to the portion of any stock-based awards settled in cash	3
Restricted stock granted to non-employee directors	28,283
Certain stock-based incentive amounts
Compensation expense (in dollars)	$ 129,000,000	$ 152,000,000	$ 78,000,000
Income tax benefit recognized in the income statement (in dollars)	46,000,000	55,000,000	29,000,000
Intrinsic value of options and stock-settled SARs exercised (in dollars)	5,000,000	24,000,000	18,000,000
Cash paid	95,000,000	96,000,000	83,000,000
Fair value of RSUs and TSRIs vested during the year	56,000,000	83,000,000	28,000,000
Unrecognized compensation expense	160,000,000
Weighted-average period over which unrecognized compensation expense is expected to be recognized	2 years
High end of range
Share-based Compensation Arrangement by Share-based Payment Award
Maximum shares available for future issuance	20,000,000
RSUs
Stock-Based Awards
Number of anniversaries for performance objectives to be satisfied	7
Award vesting period	3 years
RSUs | Low end of range
Stock-Based Awards
Award vesting period		2 years	2 years	2 years
RSUs | High end of range
Stock-Based Awards
Award vesting period		3 years	3 years	3 years
Cliff vested RSU's | Low end of range
Certain stock-based incentive amounts
Weighted-average period over which unrecognized compensation expense is expected to be recognized		2 years	2 years	2 years
Cliff vested RSU's | High end of range
Certain stock-based incentive amounts
Weighted-average period over which unrecognized compensation expense is expected to be recognized		3 years	3 years	3 years
Cash-Settled RSUs
Roll-forward of stock awards other than options and SARS.
Unvested, beginning of period (in shares)	1,431,000
Granted (in shares)	726,000
Vested (in shares)	(641,000)
Shares issued upon California Resources spin-off	76,000
Shares forfeited by employees of California Resources	(396,000)
Forfeitures (in shares)	(79,000)
Unvested, end of period (in shares)	1,117,000	1,431,000
Stock awards other than options and SARs, weighted-average grant-date fair value (in dollars per share)
Unvested, beginning of period, weighted-average grant-date fair value (in dollars per share)	$ 90.12
Granted, weighted-average grant-date fair value (in dollars per share)	$ 100.95	$ 89.70	$ 84.38
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value	$ 92.46
Shares forfeited by employees of California Resources, weighted average grant date fair value (in dollars per share)	$ 90.70
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value	$ 91.00
Unvested, end of period, weighted-average grant-date fair value (in dollars per share)	$ 89.42	$ 90.12
Stock-Settled RSUs
Roll-forward of stock awards other than options and SARS.
Unvested, beginning of period (in shares)	1,607,000
Granted (in shares)	785,000
Vested (in shares)	(553,000)
Shares issued upon California Resources spin-off	95,000
Shares forfeited by employees of California Resources	(412,000)
Forfeitures (in shares)	(97,000)
Unvested, end of period (in shares)	1,425,000	1,607,000
Stock awards other than options and SARs, weighted-average grant-date fair value (in dollars per share)
Unvested, beginning of period, weighted-average grant-date fair value (in dollars per share)	$ 90.26
Granted, weighted-average grant-date fair value (in dollars per share)	$ 101.77	$ 90.35	$ 84.81
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value	$ 94.34
Shares forfeited by employees of California Resources, weighted average grant date fair value (in dollars per share)	$ 93.30
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value	$ 92.13
Unvested, end of period, weighted-average grant-date fair value (in dollars per share)	$ 88.98	$ 90.26
Cash-settled SARs
Option and SAR transactions
Beginning balance (in shares)	352,000
Exercised (in shares)	(352,000)
Option and SAR transactions
Beginning balance, weighted average exercise price (in dollars per share)	$ 24.66
Exercised, weighted average exercise price (in dollars per share)	$ 24.66
TSRIs
Stock-Based Awards
Award vesting period	3 years
Roll-forward of stock awards other than options and SARS.
Unvested, beginning of period (in shares)	832,000
Granted (in shares)	106,000
Vested (in shares)	(300,000)
Shares issued upon California Resources spin-off	33,000
Shares forfeited by employees of California Resources	82,000
Forfeitures (in shares)	(16,000)
Unvested, end of period (in shares)	573,000	832,000
Stock awards other than options and SARs, weighted-average grant-date fair value (in dollars per share)
Unvested, beginning of period, weighted-average grant-date fair value (in dollars per share)	$ 92.49
Granted, weighted-average grant-date fair value (in dollars per share)	$ 101.95	$ 91.97	$ 84.57
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value	$ 102.97
Shares forfeited by employees of California Resources, weighted average grant date fair value (in dollars per share)	$ 87.28
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value	$ 90.65
Unvested, end of period, weighted-average grant-date fair value (in dollars per share)	$ 84.22	$ 92.49
Grant-date assumptions used in the Monte Carlo simulation models
Risk-free interest rate (as a percent)	1.00%	0.60%	0.40%
Dividend yield (as a percent)	2.80%	2.80%	2.60%
Volatility factor (as a percent)	27.00%	30.00%	34.00%
Expected life	3 years	3 years	3 years
Other disclosures
Performance-based awards settled in stock (as a percent)	100.00%	100.00%	100.00%
TSRIs | Low end of range
Other disclosures
Payouts for Performance-based awards granted (as a percent)		0.00%
Share based compensation by share based payment award maximum Award (as a percent)	0.00%	0.00%	0.00%
TSRIs | High end of range
Other disclosures
Payouts for Performance-based awards granted (as a percent)	150.00%
Share based compensation by share based payment award maximum Award (as a percent)	100.00%	100.00%	100.00%
Stock-settled SARs and Options
Roll-forward of stock awards other than options and SARS.
Shares issued upon California Resources spin-off	(3,000)
Option and SAR transactions
Beginning balance (in shares)	145,000
Exercised (in shares)	(87,000)
Ending balance (in shares)	61,000
Exercisable, end of period (in shares)	61,000
Option and SAR transactions
Beginning balance, weighted average exercise price (in dollars per share)	$ 42.11
Exercised, weighted average exercise price (in dollars per share)	$ 38.00
Shares issued upon California Resources spin-off weighted average exercise price (in dollars per share)	$ 47.87
Ending balance, weighted average exercise price (in dollars per share)	$ 45.78
Exercisable, end of period, weighted average exercise price (in dollars per share)	$ 45.78
Ending balance, weighted average remaining contractual term	1 year 3 months 18 days
Exercisable, end of period, weighted average remaining contractual term	1 year 3 months 18 days
Ending balance, aggregate intrinsic value (in dollars)	2,125,000
Exercisable, end of period, aggregate intrinsic value (in dollars)	2,125,000
Stock-settled SARs and Options | Low end of range
Stock-Based Awards
Term of award	3 years
Other awards granted in 2013
Stock-Based Awards
Award vesting period	3 years
Roll-forward of stock awards other than options and SARS.
Granted (in shares)	141,000
Other disclosures
Performance-based awards settled in stock (as a percent)	100.00%
Other awards granted in 2013 | Low end of range
Other disclosures
Payouts for Performance-based awards granted (as a percent)	0.00%
Other awards granted in 2013 | High end of range
Other disclosures
Payouts for Performance-based awards granted (as a percent)	200.00%
Stock-Settled ROCEs
Roll-forward of stock awards other than options and SARS.
Unvested, beginning of period (in shares)	158,000
Granted (in shares)	141,000
Shares issued upon California Resources spin-off	16,000
Forfeitures (in shares)	(33,000)
Unvested, end of period (in shares)	282,000
Return on assets and capital employed incentives
Unvested, beginning of period, weighted-average grant-date fair value (in dollars per share)	$ 91.90
Granted, weighted-average grant-date fair value (in dollars per share)	$ 101.95
Forfeitures, weighted-average grant-date fair value (in dollars per share)	$ 87.28
Unvested, end of period, weighted-average grant-date fair value (in dollars per share)	$ 92.25

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DOMESTIC AND FOREIGN INCOME TAXES (Tables)

12 Months Ended

Dec. 31, 2014

DOMESTIC AND FOREIGN INCOME TAXES

Domestic and foreign components of income from continuing operations before domestic and foreign income taxes

For the years ended December 31, (in millions)	Domestic			Foreign		Total
2014	$	(732	)	$	2,273	$	1,541
2013	$	3,399		$	4,747	$	8,146
2012	$	852		$	5,636	$	6,488

Provisions (credits) for domestic and foreign income taxes on continuing operations

For the years ended December 31, (in millions)	United States Federal			State and Local			Foreign			Total
2014
Current	$	870		$	81		$	1,912		$	2,863
Deferred	(1,037		)	(71		)	(70		)	(1,178		)
	$	(167	)	$	10		$	1,842		$	1,685
2013
Current	$	113		$	17		$	2,170		$	2,300
Deferred	883			48			(17		)	914
	$	996		$	65		$	2,153		$	3,214
2012
Current	$	(308	)	$	4		$	2,383		$	2,079
Deferred	519			20			41			580
	$	211		$	24		$	2,424		$	2,659

Reconciliation of the United States federal statutory income tax rate to Occidental's worldwide effective tax rate on income from continuing operations stated as a percentage of pre-tax income

For the years ended December 31,	2014		2013		2012
United States federal statutory tax rate	35	%	35	%	35	%
Other than temporary loss on available for sale investment in California Resources stock	12		—		—
Operations outside the United States	65		5		6
State income taxes, net of federal benefit	1		1		1
Other	(4	)	(1	)	(1	)
Worldwide effective tax rate	109	%	40	%	41	%

Tax effects of temporary differences resulting in deferred income taxes

	2014					2013
Tax effects of temporary differences (in millions)	Deferred Tax Assets			Deferred Tax Liabilities		Deferred Tax Assets			Deferred Tax Liabilities
Property, plant and equipment differences	$	—		$	4,081	$	—		$	8,363
Equity investments, partnerships and foreign subsidiaries	—			—		—			225
Environmental reserves	123			—		121			—
Postretirement benefit accruals	379			—		376			—
Deferred compensation and benefits	208			—		222			—
Asset retirement obligations	307			—		407			—
Foreign tax credit carryforwards	1,765			—		1,091			—
Federal benefit of state income taxes	85			—		136			—
All other	274			221		344			82
Subtotal	3,141			4,302		2,697			8,670
Valuation allowance	(1,744		)	—		(1,074		)	—
Total deferred taxes	$	1,397		$	4,302	$	1,623		$	8,670

Reconciliation of the beginning and ending amount of unrecognized tax benefits

For the years ended December 31, (in millions)	2014		2013
Balance at January 1,	$	61	$	76
Reductions based on tax positions related to prior years and settlements	—		(15		)
Balance at December 31,	$	61	$	61

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Industry Segments (Details 2) (USD $) In Millions, unless otherwise specified	0 Months Ended	12 Months Ended
	May 15, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Segment Information
Net sales		$ 19,312	$ 20,170	$ 20,100
Property, plant and equipment, net		39,730	55,821	52,064
Corporate significant items affecting earnings/Pre-tax operating profit (loss)
Corporate significant items affecting earnings/spin-off and other cost		(61)
Corporate significant items affecting earnings/charge for former executives and consultants	(55)
United States
Segment Information
Net sales		11,943	11,724	11,287
Property, plant and equipment, net		26,673	42,956	40,786
Foreign oil and gas assets
Segment Information
Net sales		7,369	8,446	8,813
Property, plant and equipment, net		13,057	12,865	11,278
Corporate significant items affecting earnings/Pre-tax operating profit (loss)
Corporate significant items affecting earnings/impairment of oil and gas properties		1,100
Qatar
Segment Information
Net sales		2,803	2,995	3,356
Property, plant and equipment, net		2,605	2,605	2,676
Oman
Segment Information
Net sales		2,524	2,567	2,578
Property, plant and equipment, net		2,876	2,509	2,353
Colombia
Segment Information
Net sales		938	1,022	1,027
Property, plant and equipment, net		1,396	1,259	1,041
United Arab Emirates
Segment Information
Property, plant and equipment, net		4,312	3,131	2,104
Other Foreign
Segment Information
Net sales		1,104	1,862	1,852
Property, plant and equipment, net		1,868	3,361	3,104
Joslyn oil sands project member
Corporate significant items affecting earnings/Pre-tax operating profit (loss)
Corporate significant items affecting earnings/other than temperary loss		(805)
Corporate
Corporate significant items affecting earnings/Pre-tax operating profit (loss)
Corporate significant items affecting earnings/Pre-tax operating profit (loss) total		(1,419)	(55)	(20)
Corporate significant items affecting earnings/Income Taxes
Corporate significant items affecting earnings/Income Taxes Total		927	(167)	612
Corporate | Litigation reserves
Corporate significant items affecting earnings/Pre-tax operating profit (loss)
Corporate significant items affecting earnings/Litigation reserves				(20)
Corporate | Charge for former executives and consultants
Corporate significant items affecting earnings/Pre-tax operating profit (loss)
Corporate significant items affecting earnings/charge for former executives and consultants			(55)
Corporate | Spin-off California Resources Corp | Premium on debt extinguishments
Corporate significant items affecting earnings/Pre-tax operating profit (loss)
Corporate significant items affecting earnings/other than temperary loss		$ (553)

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Retirement and Postretirement Benefit Plans

12 Months Ended

Dec. 31, 2014

Retirement and Postretirement Benefit Plans

Retirement and Postretirement Benefit Plans

NOTE 13RETIREMENT 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 $163 million and $166 million as of December 31, 2014 and 2013, respectively, and Occidental expensed $146 million in 2014, $140 million in 2013 and $137 million in 2012 under the provisions of these defined contribution and supplemental retirement plans.

DEFINED BENEFIT PLANS

Participation in defined benefit plans is limited and approximately 700 domestic and 1,300 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 $215 million in 2014, $229 million in 2013 and $218 million in 2012.

SPIN-OFF OF CALIFORNIA RESOURCES

In connection with the spin-off of California Resources, Occidental entered into an Employee Matters Agreement with California Resources, see Note 17, which provides that employees of California Resources no longer participate in benefit plans sponsored or maintained by Occidental as of the separation date. Upon separation, the Occidental pension and postretirement plans transferred assets and obligations to the California Resources plans resulting in a net decrease in sponsored pension and postretirement plan obligations of $15 million and $72 million, respectively. Additionally, as a result of the transfer of unrecognized losses to California Resources, deferred income taxes and other comprehensive income decreased $14 million and $36 million, respectively.

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,	2014		2013		2014		2013
Amounts recognized in the consolidated balance sheet:
Other assets	$	57	$	104	$	—	$	—
Accrued liabilities	(6)		(6)		(57)		(58)
Deferred credits and other liabilities — other	(68)		(83)		(980)		(958)
	$	(17)	$	15	$	(1,037)	$	(1,016)
AOCI included the following after-tax balances:
Net loss	$	83	$	66	$	255	$	225
Prior service cost	—		1		1		2
	$	83	$	67	$	256	$	227
For the years ended December 31,
Changes in the benefit obligation:
Benefit obligation — beginning of year	$	523	$	615	$	1,016	$	1,127
Service cost — benefits earned during the period	11		13		24		29
Interest cost on projected benefit obligation	23		24		44		43
Actuarial (gain) loss	53		(35)		83		(126)
Foreign currency exchange rate (gain) loss	(9)		(5)		—		—
Spin-off of California Resources	(105)		—		(72)		—
Benefits paid	(43)		(54)		(59)		(57)
Settlements	—		(35)		—		—
Benefit obligation — end of year	$	453	$	523	$	1,036	$	1,016
Changes in plan assets:
Fair value of plan assets — beginning of year	$	538	$	499	$	—	$	—
Actual return on plan assets	24		88		—		—
Employer contributions	7		29		—		—
Spin-off of California Resources	(90)		—		—		—
Benefits paid	(43)		(54)		—		—
Settlements	—		(24)		—		—
Fair value of plan assets — end of year	$	436	$	538	$	—	$	—
Funded/(Unfunded) status:	$	(17)	$	15	$	(1,036)	$	(1,016)

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,	2014		2013		2014		2013
Projected Benefit Obligation	$	173	$	122	$	280	$	401
Accumulated Benefit Obligation	$	168	$	112	$	280	$	386
Fair Value of Plan Assets	$	100	$	39	$	336	$	499

Occidental does not expect any plan assets to be returned during 2015.

COMPONENTS OF NET PERIODIC BENEFIT COST

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

	Pension Benefits						Postretirement Benefits
For the years ended December 31, (in millions)	2014		2013		2012		2014		2013		2012
Net periodic benefit costs:
Service cost — benefits earned during the period	$	11	$	13	$	13	$	24	$	29	$	25
Interest cost on projected benefit obligation	23		24		27		44		43		42
Expected return on plan assets	(33)		(31)		(31)		—		—		—
Recognized actuarial loss	6		19		19		20		38		37
Other costs and adjustments	(8)		(13)		17		1		1		1
Net periodic benefit cost	$	(1)	$	12	$	45	$	89	$	111	$	105

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 $10 million and zero, 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 $29 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,	2014		2013	2014	2013
Benefit Obligation Assumptions:
Discount rate	3.81%		4.45%	3.99%	4.75%
Rate of compensation increase	—	(a)	4.00%	—	—
Net Periodic Benefit Cost Assumptions:
Discount rate	4.45%		3.59%	4.75%	3.89%
Assumed long term rate of return on assets	6.50%		6.50%	—	—
Rate of compensation increase	4.00%	(a)	4.00%	—	—

(a) Plans requiring a salary increase assumption were separated with California Resources.

For domestic pension plans and postretirement benefit plans, Occidental based the discount rate on the Aon/Hewitt AA-AAA Universe yield curve in 2014 and 2013.  As of December 31, 2014, the use of a weighted average rate of increase in future compensation levels was not necessary as the retirement plans determining benefits using compensation were transferred in connection with the California Resources spin-off.  At December 31, 2013, the weighted average rate of increase in future compensation levels was consistent with Occidental’s past and anticipated future compensation increases for employees participating in retirement plans that determine benefits using compensation. The assumed long term rate of return on assets is estimated with regard to current market factors but within the context of historical returns for the asset mix that exists at year end.

In 2014, Occidental adopted the Society of Actuaries 2014 Mortality Tables Report and Mortality Improvement Scale, which updated the mortality assumptions that private defined benefit retirement plans in the United States use in the actuarial valuations that determine a plan sponsor’s pension obligations. The updated mortality data reflects increasing life expectancies in the United States, and affected plans generally expect the value of the actuarial obligations to increase, depending on the specific demographic characteristics of the plan participants and the types of benefits. The changes in the mortality table results in an increase of $27 million and $98 million in the pension and postretirement benefit obligation at December 31, 2014.

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 percent at both December 31, 2014 and 2013.  The average rate of increase in future compensation levels ranged from 1.5 percent to 10 percent in 2014, depending on local economic conditions.

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 1.79 percent and 2.36 percent as of December 31, 2014 and 2013, 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 0.25 percent per year from 7.75 percent in 2014 until they reach 5.0 percent in 2025, and remain at 5.0 percent thereafter.  A 1-percent increase or a 1-percent decrease in these assumed healthcare cost trend rates would result in an increase of $55 million or a reduction of $47 million, respectively, in the postretirement benefit obligation as of December 31, 2014.  The annual service and interest costs would not be materially affected by these changes.

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

FAIR VALUE OF PENSION PLAN ASSETS

Occidental employs a total return investment approach that uses a diversified blend of equity and fixed-income investments to optimize the long-term return of plan assets at a prudent level of risk.  The investments are monitored by Occidental’s Pension and Retirement Trust and Investment Committee (Pension Committee) in its role as fiduciary.  The Pension 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 65 percent equity securities and 35 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, 2014 Using
Description	Level 1		Level 2		Level 3		Total
Asset Class:
U.S. government securities	$	15	$	—	$	—	$	15
Corporate bonds (a)	—		76		—		76
Common/collective trusts (b)	—		13		—		13
Mutual funds:
Bond funds	42		—		—		42
Blend funds	68		—		—		68
Common and preferred stocks (c)	196		—		—		196
Other	—		38		1		39
Total pension plan assets (d)	$	321	$	127	$	1	$	449

(in millions)	Fair Value Measurements at December 31, 2013 Using
Description	Level 1		Level 2		Level 3		Total
Asset Class:
U.S. government securities	$	16	$	—	$	—	$	16
Corporate bonds (a)	—		84		—		84
Common/collective trusts (b)	—		19		—		19
Mutual funds:
Bond funds	64		—		—		64
Blend funds	105		—		—		105
Value and growth funds	6		—		—		6
Common and preferred stocks (c)	201		—		—		201
Other	—		37		11		48
Total pension plan assets (d)	$	392	$	140	$	11	$	543

(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 $13 million and $5 million as of December 31, 2014 and 2013, respectively.

The activity during the years ended December 31, 2014 and 2013, for the assets using Level 3 fair value measurements was insignificant. Occidental expects to contribute $6 million in cash to its defined benefit pension plans during 2015.

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
2015	$	38	$	58
2016	$	37	$	59
2017	$	33	$	59
2018	$	32	$	59
2019	$	32	$	60
2020— 2024	$	191	$	304

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STOCKHOLDERS' EQUITY (Tables)

12 Months Ended

Dec. 31, 2014

STOCKHOLDERS' EQUITY

Summary of common stock issuances

Shares in thousands	Common Stock
Balance, December 31, 2011	886,809
Issued	1,746
Options exercised and other, net	246
Balance, December 31, 2012	888,801
Issued	826
Options exercised and other, net	292
Balance, December 31, 2013	889,919
Issued	584
Options exercised and other, net	55
Balance, December 31, 2014	890,558

Calculation of basic and diluted EPS

(in millions, except per-share amounts)	2014			2013			2012
Basic EPS
(Loss) / Income from continuing operations	$	(130	)	$	4,932		$	3,829
Less: Income from continuing operations attributable to noncontrolling interest	(14		)	—			—
(Loss) / Income from contributing operations attributable to common stock	(144		)	4,932			3,829
Discontinued operations, net	760			971			769
Net income	616			5,903			4,598
Less: Net income allocated to participating securities	—			(13		)	(8		)
Net income, net of participating securities	$	616		$	5,890		$	4,590
Weighted average number of basic shares	781.1			804.1			809.3
Basic EPS	$	0.79		$	7.33		$	5.67
Diluted EPS
Net income, net of participating securities	$	616		$	5,890		$	4,590
Weighted average number of basic shares	781.1			804.1			809.3
Dilutive securities	—			0.5			0.7
Total diluted weighted average common shares	781.1			804.6			810.0
Diluted EPS	$	0.79		$	7.32		$	5.67

Components of accumulated other comprehensive income (loss)

Balance at December 31, (in millions)	2014			2013
Foreign currency translation adjustments	$	(7	)	$	(5	)
Unrealized losses on derivatives	(11		)	(14		)
Pension and post-retirement adjustments (a)	(339		)	(284		)
Total	$	(357	)	$	(303	)

(a) See Note 13 for further information.

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Fair Value Measurements

12 Months Ended

Dec. 31, 2014

Fair Value Measurements

Fair Value Measurements

NOTE 15FAIR VALUE MEASUREMENTS

FAIR VALUES — RECURRING

The following tables provide fair value measurement information for assets and liabilities that are measured on a recurring basis:

(in millions)	Fair Value Measurements at December 31, 2014 Using
							Netting and		Total
Description	Level 1		Level 2		Level 3		Collateral		Fair Value
Assets:
Commodity derivatives	$	712	$	127	$	—	$	(742)	$	97
Available for sale investment	$	394	$	—	$	—	$	—	$	394
Liabilities:
Commodity derivatives	$	750	$	246	$	—	$	(756)	$	240

(in millions)	Fair Value Measurements at December 31, 2013 Using
							Netting and		Total
Description	Level 1		Level 2		Level 3		Collateral		Fair Value
Assets:
Commodity derivatives	$	185	$	195	$	—	$	(329)	$	51
Liabilities:
Commodity derivatives	$	199	$	223	$	—	$	(364)	$	58

FAIR VALUES — NONRECURRING

As a result of the sharp decline of the forward price curve in the fourth quarter of 2014, Occidental recognized approximately $3.8 billion in pre-tax impairment charges related to proved oil and gas properties. Domestically, Occidental recognized $2.8 billion in pre-tax impairment charges related to domestic oil and gas properties primarily in the Williston Basin and gas and NGLs assets. Internationally, the remaining $1.0 billion related primarily to Bahrain.

The impairment tests, including the fair value estimation, incorporated a number of assumptions involving expectations of future cash flows.  These assumptions included estimates of future product prices, which Occidental based on forward price curves and, where applicable, contractual prices, estimates of oil and gas reserves, estimates of future expected operating and development costs and a risk adjusted discount rate of 8 percent.  These properties were impacted by persistently low natural gas prices and the recent decline in oil prices in the United States changing management’s development plans.  Occidental used the income approach to measure the fair value of these properties, using inputs categorized as Level 3 in the fair value hierarchy.

In 2014, Occidental recognized approximately $111 million pre-tax charges related to the impairments of Chemical assets.

(in millions)	Fair Value Measurements at December 31, 2014 Using								Total Pre-tax
							Net		(Non-cash)
Description	Level 1		Level 2		Level 3		Book Value (a)		Impairment Loss
Assets:
Impaired proved oil and gas assets - domestic	$	—	$	—	$	2,249	$	5,008	$	2,759
Impaired proved oil and gas assets - international	$	—	$	—	$	45	$	1,084	$	1,039
Impaired Chemical property, plant, and equipment	$	—	$	—	$	18	$	129	$	111

(a) Amount represents net book value at date of assessment.

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. See Note 5 for the fair value of Long-term Debt.

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Schedule II - Valuation and Qualifying Accounts (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Valuation and qualifying accounts
Balance at Beginning of Period	$ 496	$ 573	$ 558
Charged to Costs and Expenses	80	63	113
Charged to Other Accounts	183	4
Deductions	(87)	(144)	(98)
Balance at End of Period	672	496	573
Valuation and qualifying accounts, classified as current	287	101	98
Allowance for doubtful accounts
Valuation and qualifying accounts
Balance at Beginning of Period	17	16		16
Charged to Costs and Expenses	4	1
Charged to Other Accounts	(2)
Balance at End of Period	19	17		16
Environmental
Valuation and qualifying accounts
Balance at Beginning of Period	330	344	360
Charged to Costs and Expenses	79	60	56
Charged to Other Accounts	(7)
Deductions	(68)	(74)	(72)
Balance at End of Period	334	330	344
Litigation, tax and other reserves
Valuation and qualifying accounts
Balance at Beginning of Period	166	229	198
Charged to Costs and Expenses	1	3	57
Charged to Other Accounts	190	4
Deductions	(19)	(70)	(26)
Balance at End of Period	$ 338	$ 166	$ 229

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CONSOLIDATED CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
CONSOLIDATED CONDENSED STATEMENTS OF COMPREHENSIVE INCOME
Unrealized losses on derivatives, tax	$ 3	$ 2	$ (9)
Pension and postretirement gains, tax	44	(101)	(8)
Reclassification to income of realized losses (gains) on derivatives, tax	(5)	2	14
Distribution of stock of subsidiary to shareholders, tax	$ 14

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CONSOLIDATED CONDENSED BALANCE SHEETS (Parenthetical) (USD $) In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
CONSOLIDATED CONDENSED BALANCE SHEETS
Trade receivables, reserves (in dollars)	$ 17	$ 17
Common stock, per share par value (in dollars per share)	$ 0.20	$ 0.20
Common stock, authorized shares	1,100,000,000	1,100,000,000
Common stock, outstanding shares	890,557,537	889,919,058
Treasury stock, shares	119,951,199	93,928,179

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Environmental Liabilities and Expenditures

12 Months Ended

Dec. 31, 2014

Environmental Liabilities and Expenditures

Environmental Liabilities and Expenditures

NOTE 8 ENVIRONMENTAL LIABILITIES AND EXPENDITURES

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

ENVIRONMENTAL REMEDIATION

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

As of December 31, 2014, Occidental participated in or monitored remedial activities or proceedings at 145 sites, excluding seven sites transferred to California Resources prior to December 31, 2014.  The following table presents Occidental’s environmental remediation reserves as of December 31, 2014, 2013 and 2012, the current portion of which is included in accrued liabilities ($79 million in 2014, $78 million in 2013 and $80 million in 2012) and the remainder in deferred credits and other liabilities — other ($255 million in 2014, $252 million in 2013 and $264 million in 2012).  The reserves are grouped as environmental remediation sites listed or proposed for listing by the U.S. Environmental Protection Agency on the CERCLA National Priorities List (NPL sites) and three categories of non-NPL sites — third-party sites, Occidental-operated sites and closed or non-operated Occidental sites.

($ amounts in millions)	2014			2013			2012
	Number of Sites	Reserve Balance		Number of Sites	Reserve Balance		Number of Sites	Reserve Balance
NPL sites	30	$	23	31	$	25	35	$	54
Third-party sites	67	101		74	83		75	84
Occidental-operated sites	17	107		20	118		22	123
Closed or non-operated Occidental sites	31	103		32	104		29	83
Total	145	$	334	157	$	330	161	$	344

As of December 31, 2014, Occidental’s environmental reserves exceeded $10 million each at 11 of the 145 sites described above, and 98 of the sites had reserves from $0 to $1 million each.

As of December 31, 2014, two sites — a landfill in western New York owned by Occidental and a former refinery in Louisiana — accounted for 62 percent of its reserves associated with NPL sites.  In connection with a 1986 acquisition, Maxus Energy Corporation has retained the liability and is indemnifying Occidental for 14 of the remaining NPL sites.

As of December 31, 2014, Maxus has also retained the liability and is indemnifying Occidental for 8 of the 67 third-party sites.  Four of the remaining 59 third-party sites — a former copper mining and smelting operation in Tennessee, a containment and removal project in Tennessee, a former chemical plant in Ohio and an active refinery in Louisiana where Occidental reimburses the current owner for certain remediation activities — accounted for 56 percent of Occidental’s reserves associated with these sites.

Four sites — chemical plants in Kansas, Louisiana and New York and a group of oil and gas properties in the southwestern United States — accounted for 62 percent of the reserves associated with the Occidental-operated sites.

Four other sites — a landfill in western New York, former chemical plants in Tennessee and Delaware and a closed coal mine in Pennsylvania — accounted for 63 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)	2014			2013			2012
Balance — Beginning of Year	$	330		$	344		$	360
Remediation expenses and interest accretion	79			60			56
Spin-off of California Resources	(7		)	—			—
Payments	(68		)	(74		)	(72		)
Balance — End of Year	$	334		$	330		$	344

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 three to 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 $380 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)	2014		2013		2012
Operating Expenses
Oil and Gas	$	103	$	100	$	116
Chemical	80		75		70
Midstream and Marketing	11		13		13
	$	194	$	188	$	199
Capital Expenditures
Oil and Gas	$	143	$	67	$	79
Chemical	35		14		18
Midstream and Marketing	11		5		8
	$	189	$	86	$	105
Remediation Expenses
Corporate	$	79	$	60	$	56

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

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Document and Entity Information (USD $) In Billions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Jan. 31, 2015	Jun. 30, 2014
Document and Entity Information
Entity Registrant Name	OCCIDENTAL PETROLEUM CORP /DE/
Entity Central Index Key	0000797468
Document Type	10-K
Document Period End Date	Dec. 31, 2014
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$ 79.8
Entity Common Stock, Shares Outstanding		770,550,364
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY

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Lawsuits, Claims, Commitments and Contingencies

12 Months Ended

Dec. 31, 2014

Lawsuits, Claims, Commitments and Contingencies

Lawsuits, Claims, Commitments and Contingencies

NOTE 9 LAWSUITS, CLAIMS, COMMITMENTS AND CONTINGENCIES

OPC or certain of its subsidiaries are involved, in the normal course of business, in lawsuits, claims and other legal proceedings that seek, among other things, compensation for alleged personal injury, breach of contract, property damage or other losses, punitive damages, civil penalties, or injunctive or declaratory relief.  OPC or certain of its subsidiaries also are involved in proceedings under CERCLA and similar federal, state, local and foreign environmental laws.  These environmental proceedings seek funding or performance of remediation and, in some cases, compensation for alleged property damage, punitive damages, civil penalties and injunctive relief.  Usually OPC or such subsidiaries are among many companies in these environmental proceedings and have to date been successful in sharing response costs with other financially sound companies.  Further, some lawsuits, claims and legal proceedings involve acquired or disposed assets with respect to which a third party or Occidental retains liability or indemnifies the other party for conditions that existed prior to the transaction.

Occidental has entered into a written settlement agreement with the State of New Jersey (the State) to resolve claims asserted by the State against Occidental arising from Occidental’s acquisition of Diamond Shamrock Chemicals Company (DSCC) and historic operations of DSCC’s Lister Avenue Plant.  In December 2014, the settlement was approved by the court.  Under the settlement agreement (State Settlement) Occidental will pay the State $190 million and, under certain circumstances, perform or fund future work on behalf of the State along a portion of the Passaic River.  When Occidental acquired the stock of DSCC in 1986, Maxus Energy Corporation, a subsidiary of YPF S.A. (Maxus), retained liability for the Lister Avenue Plant, which is part of the Diamond Alkali Superfund Site, as well as other sites.  Maxus is also obligated to indemnify Occidental for the State of New Jersey settlement. Occidental is pursuing Maxus to recover the settlement costs.  The State Settlement does not cover any potential Occidental share of costs associated with the EPA’s proposed clean-up plan of the Passaic River announced in April 2014. Maxus is also responsible for federal clean-up or other costs associated with the Lister Avenue Plant and the Diamond Alkali Superfund Site.

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, 2014 and 2013 were not material to Occidental’s consolidated balance sheets.  Occidental also evaluates the amount of reasonably possible losses that it could incur as a result of the matters mentioned above.  Occidental has disclosed its range of reasonably possible additional losses for sites where it is a participant in environmental remediation.  Occidental believes that other reasonably possible losses that it could incur in excess of reserves accrued on the balance sheet would not be material to its consolidated financial position or results of operations.

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

OPC, its subsidiaries, or both, have entered into agreements providing for future payments to secure terminal and pipeline capacity, drilling rigs and services, electrical power, steam and certain chemical raw materials.  Occidental has certain other commitments under contracts, guarantees and joint ventures, including purchase commitments for goods and services at market-related prices and certain other contingent liabilities.  At December 31, 2014, total purchase obligations were $10 billion, which included approximately $3.3 billion, $1.7 billion, $1.0 billion, $0.7 billion and $0.5 billion that will be paid in 2015, 2016, 2017, 2018 and 2019, respectively.  Included in the purchase obligations are commitments for major fixed and determinable capital expenditures during 2015 and thereafter, which were approximately $1.4 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, 2014, Occidental is not aware of circumstances that it believes would reasonably be expected to lead to indemnity claims that would result in payments materially in excess of reserves.

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CONSOLIDATED CONDENSED STATEMENTS OF INCOME (USD $) In Millions, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
REVENUES AND OTHER INCOME
Net sales	$ 19,312	$ 20,170	$ 20,100
Interest, dividends and other income	130	107	80
Gain on sale of assets and equity investments	2,505	1,175
TOTAL REVENUES AND OTHER INCOME	21,947	21,452	20,180
COSTS AND OTHER DEDUCTIONS
Cost of sales (excludes depreciation, depletion and amortization of $4,261 in 2014, $4,204 in 2013 and $3,586 in 2012)	6,803	6,497	6,530
Selling, general and administrative and other operating expenses	1,503	1,544	1,366
Depreciation, Depletion and Amortization	4,261	4,203	3,585
Asset impairments and related items	7,379	621	1,710
Taxes other than on income	550	564	513
Exploration expense	150	140	197
Interest and debt expense, net	77	132	154
TOTAL COSTS AND OTHER DEDUCTIONS	20,723	13,701	14,055
Income before income taxes and other items	1,224	7,751	6,125
Provision for domestic and foreign income taxes	(1,685)	(3,214)	(2,659)
Income from equity investments	331	395	363
(LOSS) / INCOME FROM CONTINUING OPERATIONS	(130)	4,932	3,829
Discontinued operations, net	760	971	769
NET INCOME	630	5,903	4,598
Less: Net income attributable to noncontrolling interest	(14)
NET INCOME ATTRIBUTABLE TO COMMON STOCK	$ 616	$ 5,903	$ 4,598
BASIC EARNINGS PER COMMON SHARE (attributable to common stock)
(Loss)/Income from continuing operations (in dollars per share)	$ (0.18)	$ 6.12	$ 4.72
Discontinued operations, net (in dollars per share)	$ 0.97	$ 1.21	$ 0.95
BASIC EARNINGS PER COMMON SHARE (in dollars per share)	$ 0.79	$ 7.33	$ 5.67
DILUTED EARNINGS PER COMMON SHARE (attributable to common stock)
(Loss)/Income from continuing operations (in dollars per share)	$ (0.18)	$ 6.12	$ 4.72
Discontinued operations, net (in dollars per share)	$ 0.97	$ 1.20	$ 0.95
DILUTED EARNINGS PER COMMON SHARE (in dollars per share)	$ 0.79	$ 7.32	$ 5.67
DIVIDENDS PER COMMON SHARE (in dollars per share)	$ 2.88	$ 2.56	$ 2.16

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Accounting and Disclosure Changes

12 Months Ended

Dec. 31, 2014

Accounting and Disclosure Changes

Accounting and Disclosure Changes

NOTE 3ACCOUNTING AND DISCLOSURE CHANGES

RECENTLY ADOPTED ACCOUNTING AND DISCLOSURE CHANGES

In January 2015, the Financial Accounting Standards Board (FASB) issued rules which eliminate from GAAP the concept of extraordinary item. The presentation and disclosure guidance for items that are unusual in nature or occur infrequently will be retained and will be expanded to include items that are both unusual in nature and infrequently occurring. The rules are not expected to have an impact on Occidental’s financial statements upon adoption.

In June 2014, the FASB issued rules affecting entities that grant their employees share-based payment awards in which the terms of the awards provide that a performance target can be achieved after the requisite service period. The new rules require that a performance target that affects vesting and that could be achieved after the requisite service period be treated as a performance condition. Entities may apply the update either: (a) prospectively to all awards granted or modified after the effective date; or (b) retrospectively to all awards with performance targets that are outstanding as of the beginning of the earliest annual period presented in the financial statements and to all new or modified awards thereafter. These rules are effective for annual periods beginning on or after December 15, 2015.  The rules are not expected to have a material impact on Occidental’s financial statements upon adoption but will require assessment on an ongoing basis.

In May 2014, the FASB issued rules relating to revenue recognition.  Under the new rules, an entity will recognize revenue when it transfers promised goods or services to customers in an amount that reflects what it expects to receive in exchange for the goods or services. The rules also require more detailed disclosures related to the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. These rules are effective for the Company for interim and annual periods beginning after December 15, 2016.  The rules are not expected to have a material impact on Occidental’s financial statements upon adoption.

In April 2014, the FASB issued rules changing the requirements for reporting discontinued operations so that only the disposals of components of an entity that represent a strategic shift that has (or will have) a major effect on an entity’s operations and financial results will be reported as discontinued operations in the financial statements.  These rules are effective for annual periods beginning on or after December 15, 2014.  The rules are not expected to have a material impact on Occidental’s financial statements upon adoption.

In July 2013, the FASB issued rules requiring net, rather than gross, presentation of a deferred tax asset for a net operating loss or other tax credit and any related liability for unrecognized tax benefits.  The rules became effective on January 1, 2014, and did not have a material impact on Occidental’s financial statements.

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Asset Acquisitions, Dispositions and Other

12 Months Ended

Dec. 31, 2014

Asset Acquisitions, Dispositions and Other

Asset Acquisitions, Dispositions and Other

NOTE 2ACQUISITIONS, DISPOSITIONS AND OTHER TRANSACTIONS

2014

In December 2014, Occidental spent $1.3 billion on an acquisition in the Permian Basin totaling approximately 100,000 net acres. The assets acquired include primarily unproved oil and gas property leases and the related existing lease contracts, permits, licenses, easements, and equipment located on the properties.

On November 30, 2014, the spin-off of California Resources was completed through the pro rata distribution of 81.3 percent of the outstanding shares of common stock of California Resources to holders of Occidental common stock.  See Note 17 Spin-off of California Resources.

In November 2014, Occidental entered into an agreement with Plains All American Pipeline, L.P., Plains GP Holdings, L.P. (Plains Pipeline), and Magellan Midstream Partners, L.P. (Magellan) to sell its interest in the BridgeTex Pipeline Company, LLC (BridgeTex), which owns the BridgeTex Pipeline.  The sale of Occidental’s interest in BridgeTex includes two transactions: Plains Pipeline purchased Occidental’s interest in BridgeTex for $1.075 billion, and Magellan acquired Occidental’s interest in the southern leg of the BridgeTex Pipeline for $75 million.  Occidental recognized a pre-tax gain of $633 million.

Concurrent with the sale of its interest in the BridgeTex Pipeline Company, LLC, Occidental sold a portion of Plains Pipeline for pre-tax proceeds of $1.7 billion, resulting in a pre-tax gain of $1.4 billion.

In February 2014, Occidental entered into an agreement to sell its Hugoton Field operations in Kansas, Oklahoma and Colorado for pre-tax proceeds of $1.4 billion.  The transaction was completed in April 2014 and, after taking into account purchase price adjustments, it resulted in pre-tax proceeds of $1.3 billion.  Occidental recorded a pre-tax gain on sale of $531 million.

2013

During the year ended December 31, 2013, Occidental paid approximately $0.5 billion to acquire certain domestic oil and gas properties.

In October 2013, Occidental sold a portion of its equity interest in Plains Pipeline for approximately $1.4 billion, resulting in a pre-tax gain of approximately $1.0 billion. In addition, Occidental and Mexichem, S.A.B. de C.V. (Mexichem) formed Ingleside Ethylene, LLC (Ingleside) to build and operate an ethane steam cracking unit capable of producing 1.2 billion pounds of ethylene per year (Cracker), which is expected to begin operating in 2017.  With the ethylene produced from the Cracker, Occidental will produce vinyl chloride monomer (VCM), of which Mexichem has contracted to purchase a substantial majority.  As of December 31, 2013, Occidental had invested approximately $23 million in Ingleside for its portion of construction costs.

In May 2013, Occidental sold its investment in Carbocloro, a Brazilian chemical facility.  Occidental received net proceeds of approximately $270 million and recorded a pre-tax gain of $131 million.

Dr. Ray Irani submitted his resignation as a director, effective as of May 15, 2013, and ceased serving as an executive of Occidental.  In addition, certain other employees and several consulting arrangements were terminated during the second quarter.  As a result of these developments and actions, Occidental recorded a $55 million pre-tax charge in the second quarter for the estimated costs of Dr. Irani’s employment and post-employment benefits, and the termination of other employees and consulting arrangements.  Dr. Irani and Occidental have settled all matters relating to his separation.  The cost of the settlement was consistent with the estimated charge recorded in the second quarter.  Dr. Irani’s employment terminated in December 2013.

2012

During the year ended December 31, 2012, Occidental paid approximately $1.9 billion for domestic oil and gas properties in the Permian Basin, Williston Basin and South Texas.

In November 2012, Occidental and Magellan formed BridgeTex Pipeline Company, LLC to construct the BridgeTex Pipeline, which began service in the second half of 2014.

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INVESTMENTS AND RELATED-PARTY TRANSACTIONS

12 Months Ended

Dec. 31, 2014

INVESTMENTS AND RELATED-PARTY TRANSACTIONS

INVESTMENTS AND RELATED-PARTY TRANSACTIONS

NOTE 14 INVESTMENTS AND RELATED-PARTY TRANSACTIONS

EQUITY INVESTMENTS

As of December 31, 2014 and 2013, investments in unconsolidated entities comprised $1.2 billion and $1.5 billion of equity-method investments, respectively.

As of December 31, 2014, Occidental’s equity investments consisted mainly of a 13-percent interest in 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 $396 million, $447 million, and $526 million to Occidental in 2014, 2013 and 2012, respectively.  As of December 31, 2014, cumulative undistributed earnings of equity-method investees since their respective acquisitions was immaterial.  As of December 31, 2014, Occidental’s investments in equity investees exceeded the underlying equity in net assets by approximately $632 million, of which almost $546 million represented goodwill and the remainder comprised intangibles amortized over their estimated useful lives.

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

For the years ended December 31, (in millions)	2014		2013		2012
Revenues	$	3,090	$	3,373	$	2,667
Costs and expenses	2,774		2,987		2,310
Net income	$	316	$	386	$	357
As of December 31, (in millions)	2014		2013
Current assets	$	1,127	$	1,813
Non-current assets	$	2,925	$	4,412
Current liabilities	$	771	$	1,308
Long-term debt	$	1,701	$	2,506
Other non-current liabilities	$	83	$	163
Stockholders’ equity	$	1,498	$	2,248

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 upstream 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 operates a pipeline and is accounted for as an equity investment.

In November 2014 and October 2013, Occidental sold a portion of its equity interest in Plains Pipeline for approximately $1.7 billion and $1.4 billion, resulting in pre-tax gains of approximately $1.4 billion and $1.0 billion, respectively.

AVAILABLE FOR SALE INVESTMENT IN CALIFORNIA RESOURCES STOCK

As part of Occidental’s spin-off of its California oil and gas operations and related assets, Occidental retained an 18.7 percent interest in California Resources stock or approximately 71.5 million shares, which is recorded as an available for sale investment.

As a result of a declining trading price, Occidental recorded an other-than-temporary loss of $553 million for this available for sale investment as of December 31, 2014.  At December 31, 2014, Occidental’s available for sale investment in California Resources was $394 million.

RELATED-PARTY TRANSACTIONS

From time to time, Occidental purchases oil, NGLs, power, steam and chemicals from and sells oil, NGLs, gas, chemicals and power to certain of its equity investees and other related parties at market-related prices.  During 2014, 2013 and 2012, Occidental entered into the following related-party transactions and had the following amounts due from or to its related parties:

For the years ended December 31, (in millions)	2014		2013		2012
Sales (a)	$	835	$	663	$	419
Purchases	$	6	$	—	$	8
Services	$	27	$	30	$	17
Advances and amounts due from	$	26	$	67	$	25
Amounts due to	$	15	$	3	$	129

(a) In 2014, 2013 and 2012, sales of Occidental-produced oil and NGLs to Plains Pipeline accounted for 46 percent, 72 percent and 80 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.

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DOMESTIC AND FOREIGN INCOME TAXES

12 Months Ended

Dec. 31, 2014

DOMESTIC AND FOREIGN INCOME TAXES

DOMESTIC AND FOREIGN INCOME TAXES

NOTE 10 DOMESTIC AND FOREIGN INCOME TAXES

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

For the years ended December 31, (in millions)	Domestic			Foreign		Total
2014	$	(732	)	$	2,273	$	1,541
2013	$	3,399		$	4,747	$	8,146
2012	$	852		$	5,636	$	6,488

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
2014
Current	$	870		$	81		$	1,912		$	2,863
Deferred	(1,037		)	(71		)	(70		)	(1,178		)
	$	(167	)	$	10		$	1,842		$	1,685
2013
Current	$	113		$	17		$	2,170		$	2,300
Deferred	883			48			(17		)	914
	$	996		$	65		$	2,153		$	3,214
2012
Current	$	(308	)	$	4		$	2,383		$	2,079
Deferred	519			20			41			580
	$	211		$	24		$	2,424		$	2,659

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,	2014		2013		2012
United States federal statutory tax rate	35	%	35	%	35	%
Other than temporary loss on available for sale investment in California Resources stock	12		—		—
Operations outside the United States	65		5		6
State income taxes, net of federal benefit	1		1		1
Other	(4	)	(1	)	(1	)
Worldwide effective tax rate	109	%	40	%	41	%

The tax effects of temporary differences resulting in deferred income taxes at December 31, 2014 and 2013 were as follows:

	2014					2013
Tax effects of temporary differences (in millions)	Deferred Tax Assets			Deferred Tax Liabilities		Deferred Tax Assets			Deferred Tax Liabilities
Property, plant and equipment differences	$	—		$	4,081	$	—		$	8,363
Equity investments, partnerships and foreign subsidiaries	—			—		—			225
Environmental reserves	123			—		121			—
Postretirement benefit accruals	379			—		376			—
Deferred compensation and benefits	208			—		222			—
Asset retirement obligations	307			—		407			—
Foreign tax credit carryforwards	1,765			—		1,091			—
Federal benefit of state income taxes	85			—		136			—
All other	274			221		344			82
Subtotal	3,141			4,302		2,697			8,670
Valuation allowance	(1,744		)	—		(1,074		)	—
Total deferred taxes	$	1,397		$	4,302	$	1,623		$	8,670

The current portion of total deferred tax assets was $110 million and $150 million as of December 31, 2014 and 2013, respectively, which was reported in other current assets.  Total deferred tax assets were $1.4 billion and $1.6 billion as of December 31, 2014 and 2013, 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.  The reduction in net deferred tax liabilities from 2013 to 2014 was primarily due to the spin-off of California Resources.  See Note 17 Spin-off of California Resources.

Occidental had, as of December 31, 2014, foreign tax credit carryforwards of $1.8 billion, which expire in varying amounts through 2024, and various state operating loss carryforwards, which have varying carryforward periods through 2025.  Occidental’s valuation allowance provides for substantially all of the 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 $9.9 billion, net of foreign taxes, at December 31, 2014, 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 $140 million would be required, assuming utilization of available foreign tax credits.

Discontinued operations include income tax charges of $454 million, $550 million and $466 million in 2014, 2013 and 2012, respectively.

Additional paid-in capital was credited $4 million in 2014, $6 million in 2013 and $8 million in 2012 for an excess tax benefit from the exercise of certain stock-based compensation awards.

As of December 31, 2014, Occidental had liabilities for unrecognized tax benefits of approximately $61 million included in deferred credits and other liabilities – other, all of which, if subsequently recognized, would favorably affect Occidental’s effective tax rate.

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

For the years ended December 31, (in millions)	2014		2013
Balance at January 1,	$	61	$	76
Reductions based on tax positions related to prior years and settlements	—		(15		)
Balance at December 31,	$	61	$	61

Management believes it is unlikely that Occidental’s liabilities for unrecognized tax benefits related to existing matters would increase or decrease within the next 12 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.  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, 2014, 2013 and 2012.

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

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LEASE COMMITMENTS

12 Months Ended

Dec. 31, 2014

LEASE COMMITMENTS

LEASE COMMITMENTS

NOTE 6LEASE 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 the Company to pay for utilities, taxes, insurance and maintenance expenses.  At December 31, 2014, 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
2015	$	192
2016	169
2017	161
2018	168
2019	104
Thereafter	592
Total minimum lease payments	$	1,386

Rental expense for operating leases, net of sublease rental income for continuing operations, was $155 million in 2014, $196 million in 2013 and $165 million in 2012.  Rental expense was net of sublease income of $4 million in 2014, $3 million in 2013 and $4 million in 2012.

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Retirement and Postretirement Benefit Plans (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
DEFINED CONTRIBUTION PLANS
Accrued liabilities for the supplemental retirement plan	$ 163,000,000	$ 166,000,000
Expenses under provisions of defined contribution and supplemental retirement plans	146,000,000	140,000,000	137,000,000
Postretirement and Other Benefit Plans Disclosure
Total benefit costs including postretirement costs	215,000,000	229,000,000	218,000,000
AOCI included the following after-tax balances
AOCI after-tax balances	339,000,000	284,000,000
Spin-off California Resources Corp
Postretirement and Other Benefit Plans Disclosure
Increase (Decrease) in Postretirement Obligations	15,000,000	72,000,000
Increase (Decrease) in Deferred Income Taxes	14,000,000
Increase (decrease) in other comprehensive income	36,000,000
Pension Benefit
Postretirement and Other Benefit Plans Disclosure
Increase (Decrease) in Pension Plan Obligations	27,000,000
Amounts recognized in the consolidated balance sheets
Other assets	57,000,000	104,000,000
Accrued liabilities	(6,000,000)	(6,000,000)
Deferred credits and other liabilities - other	(68,000,000)	(83,000,000)
Amounts recognized in the consolidated balance sheets, total	(17,000,000)	15,000,000
AOCI included the following after-tax balances
Net loss	83,000,000	66,000,000
Prior service cost		1,000,000
AOCI after-tax balances	83,000,000	67,000,000
Changes in the benefit obligation:
Benefit obligation - beginning of year	523,000,000	615,000,000
Service cost	11,000,000	13,000,000	13,000,000
Interest cost	23,000,000	24,000,000	27,000,000
Actuarial (gain) loss	53,000,000	(35,000,000)
Foreign currency exchange rate (gain) loss	(9,000,000)	(5,000,000)
Spin-off of California Resources	(105,000,000)
Benefits paid	(43,000,000)	(54,000,000)
Settlements		(35,000,000)
Benefit obligation - end of year	453,000,000	523,000,000	615,000,000
Changes in plan assets:
Fair value of plan assets - beginning of year	538,000,000	499,000,000
Actual return on plan assets	24,000,000	88,000,000
Employer contributions	7,000,000	29,000,000
Spin-off of California Resources	(90,000,000)
Benefits paid	(43,000,000)	(54,000,000)
Settlements		(24,000,000)
Fair value of plan assets - end of year	436,000,000	538,000,000	499,000,000
Funded/(Unfunded) status:	(17,000,000)	15,000,000
Pension plans with accumulated benefit obligations in excess of plan assets
Pension plans with accumulated benefit obligations in excess of plan assets, projected benefit obligation	173,000,000	122,000,000
Pension plans with accumulated benefit obligations in excess of plan assets, accumulated benefit obligation	168,000,000	112,000,000
Pension plans with accumulated benefit obligations in excess of plan assets, fair value of plan assets	100,000,000	39,000,000
Pension plans with plan assets in excess of accumulated benefit obligations
Pension plans with plan assets in excess of accumulated benefit obligations, projected benefit obligation	280,000,000	401,000,000
Pension plans with plan assets in excess of accumulated benefit obligations, accumulated benefit obligation	280,000,000	386,000,000
Pension plans with plan assets in excess of accumulated benefit obligations, fair value of plan assets	336,000,000	499,000,000
Net periodic benefit costs:
Service cost	11,000,000	13,000,000	13,000,000
Interest cost	23,000,000	24,000,000	27,000,000
Expected return on plan assets	(33,000,000)	(31,000,000)	(31,000,000)
Recognized actuarial loss	6,000,000	19,000,000	19,000,000
Other costs and adjustments	(8,000,000)	(13,000,000)	17,000,000
Net periodic benefit cost	(1,000,000)	12,000,000	45,000,000
Amounts that will be amortized from accumulated other comprehensive income (Loss) in next fiscal year
Estimated net loss that will be amortized from AOCI into net periodic benefit cost over the next fiscal year	10,000,000
Estimated prior service cost that will be amortized from AOCI into net periodic benefit cost over the next fiscal year	0
Benefit Obligation Assumptions:
Discount rate (as a percent)	3.81%	4.45%
Rate of compensation increase (as a percent)		4.00%
Net Periodic Benefit Cost Assumptions:
Discount rate (as a percent)	4.45%	3.59%
Assumed long tem rate of return on assets in excess of inflation (as a percent)	6.50%	6.50%
Rate of compensation increase (as a percent)	4.00%	4.00%
Domestic Pension Benefits
Postretirement and Other Benefit Plans Disclosure
Number of employees accruing benefits under defined benefit plans	700
Foreign Pension Plans
Postretirement and Other Benefit Plans Disclosure
Number of employees accruing benefits under defined benefit plans	1,300
Foreign Pension Plans | High end of range
Net Periodic Benefit Cost Assumptions:
Discount rate (as a percent)		10.00%	10.00%
Rate of compensation increase (as a percent)	10.00%
Foreign Pension Plans | Low end of range
Net Periodic Benefit Cost Assumptions:
Discount rate (as a percent)		1.50%	1.50%
Rate of compensation increase (as a percent)	1.50%
Postretirement Benefit
Postretirement and Other Benefit Plans Disclosure
Increase (Decrease) in Postretirement Obligations	98,000,000
Amounts recognized in the consolidated balance sheets
Accrued liabilities	(57,000,000)	(58,000,000)
Deferred credits and other liabilities - other	(980,000,000)	(958,000,000)
Amounts recognized in the consolidated balance sheets, total	(1,037,000,000)	(1,016,000,000)
AOCI included the following after-tax balances
Net loss	255,000,000	225,000,000
Prior service cost	1,000,000	2,000,000
AOCI after-tax balances	256,000,000	227,000,000
Changes in the benefit obligation:
Benefit obligation - beginning of year	1,016,000,000	1,127,000,000
Service cost	24,000,000	29,000,000	25,000,000
Interest cost	44,000,000	43,000,000	42,000,000
Actuarial (gain) loss	83,000,000	(126,000,000)
Spin-off of California Resources	(72,000,000)
Benefits paid	(59,000,000)	(57,000,000)
Benefit obligation - end of year	1,036,000,000	1,016,000,000	1,127,000,000
Changes in plan assets:
Funded/(Unfunded) status:	(1,036,000,000)	(1,016,000,000)
Net periodic benefit costs:
Service cost	24,000,000	29,000,000	25,000,000
Interest cost	44,000,000	43,000,000	42,000,000
Recognized actuarial loss	20,000,000	38,000,000	37,000,000
Other costs and adjustments	1,000,000	1,000,000	1,000,000
Net periodic benefit cost	89,000,000	111,000,000	105,000,000
Amounts that will be amortized from accumulated other comprehensive income (Loss) in next fiscal year
Estimated net loss that will be amortized from AOCI into net periodic benefit cost over the next fiscal year	29,000,000
Estimated prior service cost that will be amortized from AOCI into net periodic benefit cost over the next fiscal year	1,000,000
Benefit Obligation Assumptions:
Discount rate (as a percent)	3.99%	4.75%
Net Periodic Benefit Cost Assumptions:
Discount rate (as a percent)	4.75%	3.89%
Assumed health care cost trend rates
Consumer Price Index (CPI) increase (as a percent)	1.79%	2.36%
Projected annual rates of health care cost trend rates (as a percent)	7.75%
Projected ultimate health care cost trend rates (as a percent)	5.00%
Year the projected health care cost trend rate reaches ultimate trend rate	2025
Increase (decrease) in projected annual rates of health care cost trend rates (as a percent)	(0.25%)
Effect of 1-percent increase or a 1-percent decrease in these assumed health care cost trend rates
Effect of 1-percent increase in assumed health care cost trend rates on postretirement benefit obligation	55,000,000
Effect of 1-percent decrease in assumed health care cost trend rates on postretirement benefit obligation	$ 47,000,000

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Inventories

12 Months Ended

Dec. 31, 2014

Inventories

Inventories

NOTE 4INVENTORIES

Net carrying values of inventories valued under the LIFO method were approximately $199 million and $205 million at December 31, 2014 and 2013, respectively.  Inventories consisted of the following:

Balance at December 31, (in millions)	2014			2013
Raw materials	$	71		$	74
Materials and supplies	585			628
Finished goods	485			589
	1,141			1,291
Revaluation to LIFO	(89		)	(91		)
Total	$	1,052		$	1,200

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LONG-TERM DEBT

12 Months Ended

Dec. 31, 2014

LONG-TERM DEBT

LONG-TERM DEBT

NOTE 5LONG-TERM DEBT

Long-term debt consisted of the following:

Balance at December 31, (in millions)	2014			2013
1.75% senior notes due 2017	$	1,250		$	1,250
4.10% senior notes due 2021	1,249			1,249
2.70% senior notes due 2023	1,191			1,224
3.125% senior notes due 2022	813			887
4.125% senior notes due 2016	750			750
2.5% senior notes due 2016	700			700
1.50% senior notes due 2018	500			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 (0.04% as of December 31, 2014 and 2013)	68			68
8.75% medium-term notes due 2023	22			22
	6,857			6,964
Less:
Unamortized discount, net	(19		)	(25		)
Current maturities	—			—
Total	$	6,838		$	6,939

Occidental has a bank credit facility (Credit Facility) with a $2.0 billion commitment expiring in 2019.  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 0.07 percent in 2014 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, 2014, 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 2014, Occidental repurchased approximately $107 million of various senior notes due in 2022 and later.

In December 2013, all $600 million of the outstanding 1.45-percent senior notes due 2013 matured.  In addition, Occidental repurchased approximately $90 million of various senior notes due in 2021 and later.

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 has provided guarantees on Dolphin Energy’s debt, which are limited to certain political and other events.  At December 31, 2014 and 2013, Occidental’s total guarantees were not material and a substantial majority of the amounts consisted of limited recourse guarantees on approximately $336 million and $354 million, respectively, of Dolphin’s debt.  The fair value of the guarantees was immaterial.

Occidental has guaranteed certain obligations of its subsidiaries for various letters of credit, indemnities and commitments. Marketing guarantees provided to third parties for California Resources total approximately $161 million as of December 31, 2014. The fair value of the marketing guarantees and other obligations of California Resources guaranteed by Occidental were immaterial.

At December 31, 2014, principal payments on long-term debt aggregated approximately $6.9 billion, of which none is due in 2015, $1.5 billion is due in 2016, $1.3 billion is due in 2017, $0.5 billion is due in 2018, $0.1 billion is due in 2019 and $3.5 billion is due in 2020 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, 2014 and 2013, substantially all of which were classified as Level 1, were approximately $7.0 billion and $7.1 billion, respectively, compared to carrying values of approximately $6.9 billion and $7.0 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, 2014 and 2013, variable-rate debt constituted approximately one percent of Occidental’s total debt.

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Derivatives

12 Months Ended

Dec. 31, 2014

Derivatives

Derivatives

NOTE 7DERIVATIVES

Objective & Strategy

Occidental uses a variety of derivative instruments, including cash-flow hedges and derivative instruments not designated as hedging instruments, to obtain the average prices for the relevant production month 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.

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

Cash-Flow Hedges

Occidental’s marketing and trading operations, from time to time, store natural gas purchased from third parties at Occidental’s North American leased storage facilities.  Derivative instruments used to fix margins on the future sales of the stored volumes ended March 31, 2014.  As of December 31, 2014, Occidental did not have any cash-flow hedges on stored volumes of natural gas.  At December 31, 2013, Occidental had approximately 11 billion cubic feet of natural gas held in storage, and had cash-flow hedges for the forecast sale, to be settled by physical delivery, of approximately 13 billion cubic feet of stored natural gas.

The following table presents the 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, 2014 and 2013:

	After-tax
As of December 31, (in millions)	2014			2013
Unrealized losses recognized in AOCI	$	(5	)	$	(3	)
Losses (Gains) reclassified to income	$	8		$	(4	)

Occidental reclassified all of the outstanding balances as of 2013 net after-tax derivative losses from AOCI into net sales during 2014.  The amount of the ineffective portion of cash-flow hedges was immaterial for the years ended December 31, 2014 and 2013.

Derivatives Not Designated as Hedging Instruments

The following table summarizes Occidental’s net volumes of outstanding commodity derivatives contracts not designated as hedging instruments, including both financial and physical derivative contracts as of December 31, 2014 and 2013:

	Net Outstanding Position Long / (Short)
Commodity	2014		2013
Oil (million barrels)	(9	)	(22	)
Natural gas (billion cubic feet)	(32	)	(10	)
CO2 (million cubic feet)	621		—

The volumes in the table above exclude contracts tied to index prices, for which the fair value, if any, is minimal at any point in time.  These contracts do not expose Occidental to price risk because the contract prices fluctuate with index prices.

Occidental fulfills its short positions through its own production or by third-party purchase contracts.  Subsequent to December 31, 2014, 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 $71 million net loss and $11 million net gain from derivatives not designated as hedging instruments were recognized in net sales for the years ended December 31, 2014 and 2013, respectively.

Fair Value of Derivatives

The following table presents the gross and net fair values of Occidental’s outstanding derivatives as of December 31, 2014 and 2013:

(in millions)
December 31, 2014	Asset Derivatives Balance Sheet Location	Fair Value			Liability Derivatives Balance Sheet Location	Fair Value
Cash-flow hedges (a)
Commodity contracts	Other current assets	$	—		Accrued liabilities	$	—
	Long-term receivables and other assets, net	—			Deferred credits and other liabilities	—
		$	—			$	—
Derivatives not designated as hedging instruments (a)
Commodity contracts	Other current assets	$	828		Accrued liabilities	$	886
	Long-term receivables and other assets, net	11			Deferred credits and other liabilities	110
		839				996
Total gross fair value		839				996
Less: counterparty netting and cash collateral (b) (d)		(742		)		(756		)
Total net fair value of derivatives		$	97			$	240

(in millions)

December 31, 2013	Asset Derivatives Balance Sheet Location	Fair Value			Liability Derivatives Balance Sheet Location	Fair Value
Cash-flow hedges (a)
Commodity contracts	Other current assets	$	—		Accrued liabilities	$	4
	Long-term receivables and other assets, net	—			Deferred credits and other liabilities	—
		$	—			$	4
Derivatives not designated as hedging instruments (a)
Commodity contracts	Other current assets	$	367		Accrued liabilities	$	407
	Long-term receivables and other assets, net	13			Deferred credits and other liabilities	11
		380				418
Total gross fair value		380				422
Less: counterparty netting and cash collateral (c) (d)		(329		)		(364		)
Total net fair value of derivatives		$	51			$	58

(a)	Fair values are presented at gross amounts, including when the derivatives are subject to master netting arrangements and presented on a net basis in the consolidated balance sheets.
(b)	As of December 31, 2014, collateral received of zero has been netted against derivative assets and collateral paid of $8 million has been netted against derivative liabilities.
(c)	As of December 31, 2013, collateral received of $11 million has been netted against derivative assets and collateral paid of $46 million has been netted against derivative liabilities.
(d)	Select clearinghouses and brokers require Occidental to post an initial margin deposit. Collateral, mainly for initial margin, of $44 million and $103 million as of December 31, 2014 and 2013, respectively, deposited by Occidental, has not been reflected in these derivative fair value tables. This collateral is included in other current assets in the consolidated balance sheets.

See Note 15 for fair value measurement disclosures on derivatives.

Credit Risk

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

Certain of Occidental’s OTC derivative instruments contain credit-risk-contingent features, primarily tied to credit ratings for Occidental or its counterparties, which may affect the amount of collateral that each would need to post.  As of December 31, 2014 and 2013, Occidental had a net liability of $4 million and $8 million, respectively, which are net of collateral posted of $3 million and $23 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, 2014 and 2013.

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, 2014, 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.

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Industry Segments (Details) (USD $)	12 Months Ended			0 Months Ended	1 Months Ended
	Dec. 31, 2014 segment	Dec. 31, 2013 segment	Dec. 31, 2012 segment	Nov. 30, 2014	Oct. 31, 2013	Apr. 30, 2014	May 31, 2013
Industry Segments
Number of operating segments	3	3	3
Segment Information
Net sales	$ 19,312,000,000	$ 20,170,000,000	$ 20,100,000,000
Pretax operating profit (loss)	1,555,000,000	8,146,000,000	6,488,000,000
Less: Income from continuing operations attributable to noncontrolling interest	(14,000,000)
Income taxes	(1,685,000,000)	(3,214,000,000)	(2,659,000,000)
Discontinued operations, net	760,000,000	971,000,000	769,000,000
Net income	616,000,000	5,903,000,000	4,598,000,000
Investments in unconsolidated entities	1,171,000,000	1,459,000,000	1,894,000,000
Property, plant and equipment additions, net	9,110,000,000	7,494,000,000	7,974,000,000
Depreciation, Depletion and Amortization	4,261,000,000	4,203,000,000	3,585,000,000
Total assets	56,259,000,000	69,443,000,000	64,210,000,000
Asset impairments and related items	7,379,000,000	621,000,000	1,710,000,000
Pre-tax gain on sale of investment	2,505,000,000	1,175,000,000
Foreign oil and gas assets
Segment Information
Net sales	7,369,000,000	8,446,000,000	8,813,000,000
Pre-tax impairment of oil and gas properties	1,100,000,000
Colombia
Segment Information
Net sales	938,000,000	1,022,000,000	1,027,000,000
Domestic oil and gas assets
Segment Information
Pre-tax impairment of oil and gas properties	4,700,000,000
BridgeTex
Segment Information
Pre-tax gain on sale of investment	633,000,000			633,000,000
Oil and Gas
Segment Information
Asset impairments and related items			1,700,000,000
Oil and Gas | Non-producing domestic oil and gas acreage member
Segment Information
Pre-tax impairment of oil and gas properties		607,000,000
Oil and Gas | Oil
Segment Information
Product revenue to net sales (as a percent)	90.00%	91.00%	91.00%
Chemical
Segment Information
Impaired property, plant and equipment	149,000,000
Pre-tax impairment of oil and gas properties	111,000,000
Chemical | Basic Chemicals
Segment Information
Product revenue to net sales (as a percent)	54.00%	55.00%	57.00%
Chemical | Vinyls
Segment Information
Product revenue to net sales (as a percent)	43.00%	42.00%	40.00%
Chemical | Other Chemicals
Segment Information
Product revenue to net sales (as a percent)	3.00%	3.00%	3.00%
Midstream and Marketing | Gas Processing
Segment Information
Sales revenues for businesses as a percentage of total sales revenues	49.00%	54.00%	60.00%
Midstream and Marketing | Power
Segment Information
Sales revenues for businesses as a percentage of total sales revenues	31.00%	30.00%	24.00%
Midstream and Marketing | Marketing, Trading, Transportation and other
Segment Information
Sales revenues for businesses as a percentage of total sales revenues	20.00%	16.00%	16.00%
Operating segments | Oil and Gas
Segment Information
Net sales	13,887,000,000	15,008,000,000	14,953,000,000
Pretax operating profit (loss)	428,000,000	6,411,000,000	5,840,000,000
Net income	428,000,000	6,411,000,000	5,840,000,000
Investments in unconsolidated entities	11,000,000	108,000,000	113,000,000
Property, plant and equipment additions, net	6,589,000,000	5,456,000,000	6,067,000,000
Depreciation, Depletion and Amortization	3,701,000,000	3,676,000,000	3,065,000,000
Total assets	31,072,000,000	46,213,000,000	44,004,000,000
Operating segments | Chemical
Segment Information
Net sales	4,817,000,000	4,673,000,000	4,580,000,000
Pretax operating profit (loss)	420,000,000	743,000,000	720,000,000
Net income	420,000,000	743,000,000	720,000,000
Investments in unconsolidated entities	202,000,000	34,000,000	108,000,000
Property, plant and equipment additions, net	325,000,000	435,000,000	365,000,000
Depreciation, Depletion and Amortization	367,000,000	346,000,000	345,000,000
Total assets	3,917,000,000	3,947,000,000	3,854,000,000
Operating segments | Midstream and Marketing
Segment Information
Net sales	1,373,000,000	1,174,000,000	1,164,000,000
Pretax operating profit (loss)	2,578,000,000	1,523,000,000	440,000,000
Less: Income from continuing operations attributable to noncontrolling interest	(14,000,000)
Net income	2,564,000,000	1,523,000,000	440,000,000
Investments in unconsolidated entities	948,000,000	1,307,000,000	1,662,000,000
Property, plant and equipment additions, net	2,093,000,000	1,437,000,000	1,451,000,000
Depreciation, Depletion and Amortization	160,000,000	149,000,000	148,000,000
Total assets	12,283,000,000	14,374,000,000	12,762,000,000
Corporate and Eliminations
Segment Information
Net sales	(765,000,000)	(685,000,000)	(597,000,000)
Pretax operating profit (loss)	(1,871,000,000)	(531,000,000)	(512,000,000)
Income taxes	(1,685,000,000)	(3,214,000,000)	(2,659,000,000)
Discontinued operations, net	760,000,000	971,000,000	769,000,000
Net income	(2,796,000,000)	(2,774,000,000)	(2,402,000,000)
Investments in unconsolidated entities	10,000,000		11,000,000
Property, plant and equipment additions, net	103,000,000	166,000,000	91,000,000
Depreciation, Depletion and Amortization	33,000,000	32,000,000	27,000,000
Total assets	8,987,000,000	4,909,000,000	3,590,000,000
Impaired property, plant and equipment		10,000,000
Other charges	31,000,000	58,000,000
General Partner of Plains All American Pipeline,L.P
Segment Information
Pre-tax gain on sale of investment	1,351,000,000
Gain on sale of investments and other items		1,044,000,000			1,044,000,000
Hugoton Field operations
Segment Information
Pre-tax gain on sale	531,000,000					531,000,000
Carbocloro member | Chemical
Segment Information
Pre-tax gain on sale of investment		$ 131,000,000					$ 131,000,000

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Spin-off of California Resources Corporation (Details) (Spin-off California Resources Corp, USD $) In Millions, unless otherwise specified	1 Months Ended
	Nov. 30, 2014	Dec. 31, 2014
Spin-off California Resources Corp
Acquistions, dispositions and other transactions
Percentage of common stock distributed	81.30%
Common Stock Conversion Ratio	0.4
Distribution of restricted cash to pay obligations of spin-off agreements	$ 4,950
Distribution of cash to pay obligations of spin-off agreements	1,150
Shares owned by Occidental	71.5
Senior Notes issued	5,000
Borrowings under term loan facility	1,000
Borrowings under revolving credit facility	2,000
Period Following Spin-off within which cash will be distributed to satisfy spin off obligations	P18M
Remaining balance of cash distribution included in restricted cash on balance sheet		$ 4,000
Period for the provision of specified transition services	24 months

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Fair Value Measurements (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended			3 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2014
Fair Value - Other Financial Instruments
Debt carrying value	$ 6,857	$ 6,964		$ 6,857
Asset impairments and related items	7,379	621	1,710
Risk adjusted discount rate	8
Chemical
Fair Value - Other Financial Instruments
Pre-tax impairment of oil and gas properties	111
Impaired property, plant and equipment	149
Proved oil and gas assets - domestic
Fair Value - Other Financial Instruments
Pre-tax impairment of oil and gas properties	2,759
Proved oil and gas assets - international
Fair Value - Other Financial Instruments
Pre-tax impairment of oil and gas properties	1,039
Level 3 | Chemical
Fair Value - Other Financial Instruments
Carrying value of impaired assets	18			18
Level 3 | Proved oil and gas assets - domestic
Fair Value - Other Financial Instruments
Carrying value of impaired assets	2,249			2,249
Level 3 | Proved oil and gas assets - international
Fair Value - Other Financial Instruments
Carrying value of impaired assets	45			45
Net Book Value | Chemical
Fair Value - Other Financial Instruments
Net book value of impaired assets	129			129
Net Book Value | Proved oil and gas assets - domestic
Fair Value - Other Financial Instruments
Net book value of impaired assets	5,008			5,008
Net Book Value | Proved oil and gas assets - international
Fair Value - Other Financial Instruments
Net book value of impaired assets	1,084			1,084
Recurring | Level 1
Assets:
Commodity derivatives	712	185		712
Available for sale investment	394			394
Liabilities:
Commodity derivatives	750	199		750
Recurring | Level 2
Assets:
Commodity derivatives	127	195		127
Liabilities:
Commodity derivatives	246	223		246
Recurring | Netting and Collateral
Assets:
Commodity derivatives	(742)	(329)		(742)
Liabilities:
Commodity derivatives	(756)	(364)		(756)
Recurring | Total Fair Value
Assets:
Commodity derivatives	97	51		97
Available for sale investment	394			394
Liabilities:
Commodity derivatives	240	58		240
Non recurring | Domestic and international proved and unproved oil and gas properties member
Fair Value - Other Financial Instruments
Pre-tax impairment of oil and gas properties				3,800
Non recurring | Williston basin and South Texas oil and gas properties member
Fair Value - Other Financial Instruments
Pre-tax impairment of oil and gas properties				2,800
Non recurring | Bahrain oil and gas properties member
Fair Value - Other Financial Instruments
Pre-tax impairment of oil and gas properties				$ 1,000

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Environmental Liabilities and Expenditures (Tables)

12 Months Ended

Dec. 31, 2014

Environmental Liabilities and Expenditures

Environmental loss contingencies by categories of sites

($ amounts in millions)	2014			2013			2012
	Number of Sites	Reserve Balance		Number of Sites	Reserve Balance		Number of Sites	Reserve Balance
NPL sites	30	$	23	31	$	25	35	$	54
Third-party sites	67	101		74	83		75	84
Occidental-operated sites	17	107		20	118		22	123
Closed or non-operated Occidental sites	31	103		32	104		29	83
Total	145	$	334	157	$	330	161	$	344

Environmental reserve activity

(in millions)	2014			2013			2012
Balance — Beginning of Year	$	330		$	344		$	360
Remediation expenses and interest accretion	79			60			56
Spin-off of California Resources	(7		)	—			—
Payments	(68		)	(74		)	(72		)
Balance — End of Year	$	334		$	330		$	344

Environmental cost for each segment

(in millions)	2014		2013		2012
Operating Expenses
Oil and Gas	$	103	$	100	$	116
Chemical	80		75		70
Midstream and Marketing	11		13		13
	$	194	$	188	$	199
Capital Expenditures
Oil and Gas	$	143	$	67	$	79
Chemical	35		14		18
Midstream and Marketing	11		5		8
	$	189	$	86	$	105
Remediation Expenses
Corporate	$	79	$	60	$	56

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Derivatives (Details 2) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
After-tax Derivative Activity recorded in AOCI
Unrealized (losses) gains recognized in AOCI	$ (5)	[1]	$ (3)	[1]	$ 16	[1]
Reclassification to income of realized losses (gains) on derivatives	$ 8	[2]	$ (4)	[2]	$ (24)	[2]

[1] Net of tax of $3, $2 and $(9) in 2014, 2013 and 2012, respectively.

[2] Net of tax of $(5), $2 and $14 in 2014, 2013 and 2012, respectively.

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STOCK-BASED INCENTIVE PLANS

12 Months Ended

Dec. 31, 2014

STOCK-BASED INCENTIVE PLANS

STOCK-BASED INCENTIVE PLANS

NOTE 12STOCK-BASED INCENTIVE PLANS

Occidental has established several plans that allow it to issue stock-based awards including in the form of RSUs, stock options (Options), stock appreciation rights (SARs), ROCEI/ROAI and TSRIs.  An aggregate of 66 million shares of Occidental common stock were authorized for issuance and approximately 17 million shares had been issued through December 31, 2014.  Of the remaining shares, only approximately 20 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 are available for future awards.  Accordingly, the number of shares available for future awards may be less than 20 million depending on the type of award granted.  Additionally, under the plan, the shares available for future awards may increase, depending on the award type, 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 canceled, or (iii) correspond to the portion of any stock-based awards settled in cash.

During 2014, non-employee directors were granted awards for 28,283 shares of common stock.  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.

California Resources Spin-off Adjustments

In connection with the separation of California Resources, Occidental entered into an Employee Matters Agreement with California Resources, which provided that employees of California Resources no longer participate in incentive programs sponsored or maintained by Occidental. Pursuant to the Employee Matters Agreement, Occidental made certain adjustments, using volumetric weighted-average prices for the 4-day period immediately prior to and immediately following the separation, to the exercise price and number of share-based compensation awards, with the intention of preserving the intrinsic value of the awards immediately prior to the separation for all Occidental employees. These adjustments are summarized as follows:

· Any unvested long-term incentive award units or shares, including Total Shareholder Return Incentives (TSRI), Return on Capital Employed Incentives (ROCEI), Return on Asset Incentives (ROAI), Restricted Stock Incentives (RSI), Long-Term Incentives (LTI) and Phantom Share Units (PHSU) were adjusted by multiplying the pre-spin number of units held by the quotient of the simple average of the volume weighted average price per share of Oxy stock for the four trading days immediately prior to and the four trading days immediate after the date of spin-off. Post-spin units were rounded up to the next whole number.

· For outstanding option awards, the strike price was adjusted (reduced) by the same quotient as described above.

· Performance periods, performance targets and vesting dates of Long-Term Incentive awards were not adjusted.

· Pursuant to the terms of all outstanding TSRI awards, the spin-off was treated as a dividend.

The separation-related adjustments did not have a material impact on either compensation expense for the year ended December 31, 2014, or the number of potentially dilutive securities as of December 31, 2014.

The following table summarizes total share-based compensation expense recognized in income related to continuing and discontinued operations and the associated tax benefit for the years ended December 31:

For the years ended December 31, (in millions)	2014		2013		2012
Compensation expense	$	129	$	152	$	78
Income tax benefit recognized in the income statement	46		55		29
Intrinsic value of options and stock-settled SARs exercised	5		24		18
Cash paid (a)	95		96		83
Fair value of RSUs and TSRIs vested during the year (b)	56		83		28

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

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

As of December 31, 2014, unrecognized compensation expense for all unvested stock-based incentive awards was $160 million.  This expense is expected to be recognized over a weighted-average period of 2.0 years.

RSUs

Certain employees are awarded the right to receive RSUs, some of which have performance criteria, and are in the form of, or equivalent in value to, actual shares of Occidental common stock.  Depending on their terms, RSUs are settled in cash or stock at the time of vesting.  These awards vest ratably over three years, or at the end of two or three years, following the grant date, however, certain of the RSUs are forfeitable if performance objectives are not satisfied by the seventh anniversary of the grant date.  For certain three-year RSUs, dividend equivalents are paid during the vesting period.  For those awards that cliff vest in two or three years, dividend equivalents are accumulated during the vesting period and are paid when they vest.

The weighted-average, grant-date fair values of cash-settled RSUs granted in 2014, 2013 and 2012 were $100.95, $89.70, and $84.38 per share, respectively.  The weighted-average, grant-date fair values of the stock-settled RSUs granted in 2014, 2013, and 2012 were $101.77, $90.35 and $84.81, respectively.

A summary of changes in Occidental’s unvested cash- and stock-settled RSUs during the year ended December 31, 2014 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	1,431			$	90.12	1,607			$	90.26
Granted	726			100.95		785			101.77
Vested	(641	)		92.46		(553	)		94.34
Shares issued upon California Resources spin-off	76			—		95			—
Shares forfeited by employees of California Resources	(396	)		90.70		(412	)		93.30
Forfeitures	(79	)		91.00		(97	)		92.13
Unvested at December 31	1,117			89.42		1,425			88.98

TSRIs

Certain executives are awarded TSRIs that vest at the end of a three-year period following the grant date if performance targets are certified as being met. TSRIs granted in July 2014 and 2013 have payouts that range from 0 to 150 percent of the target award; TSRIs granted in 2012 have payouts that range from 0 to 100 percent of the maximum award. All outstanding TSRIs settle fully in stock once certified. Dividend equivalents for TSRIs are accumulated and 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	2014			2013			2012
Assumptions used:
Risk-free interest rate	1.0		%	0.6		%	0.4		%
Dividend yield	2.8		%	2.8		%	2.6		%
Volatility factor	27		%	30		%	34		%
Expected life (years)	3			3			3
Grant-date fair value of underlying Occidental common stock	$	101.95		$	91.97		$	84.57

A summary of Occidental’s unvested TSRIs as of December 31, 2014, and changes during the year ended December 31, 2014, is presented below:

	TSRIs
	Awards (000’s)		Weighted-Average Grant-Date Fair Value of Occidental Stock
Unvested at January 1 (a)	832			$	92.49
Granted (a)	106			101.95
Vested (a)	(300	)		102.97
Forfeitures	(16	)		90.65
Shares issued upon California Resources spin-off	33			—
Shares forfeited by employees of California Resources	(82	)		87.28
Unvested at December 31 (a)	573			84.22

(a) Presented at the target or mid-point payouts.

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.  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 US Treasury Strips 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, 2014:

	Cash-Settled						Stock-Settled
	SARs (000’s)	Weighted- Average Exercise Price		Weighted- Average Remaining Contractual Term (yrs)	Aggregate Intrinsic Value (000’s)		SARs & Options (000’s)	Weighted- Average Exercise Price		Weighted- Average Remaining Contractual Term (yrs)	Aggregate Intrinsic Value (000’s)
Beginning balance, January 1	352	$	24.66				145	$	42.11
Exercised	(352)	$	24.66				(87)	$	38.00
Shares issued upon California Resources spin-off	—	$	—				3	$	47.87
Ending balance, December 31	—	$	—	—	$	—	61	$	45.78	1.3	$	2,125
Exercisable at December 31	—	$	—	—	$	—	61	$	45.78	1.3	$	2,125

ROCEI / ROAI

During 2014, Occidental also granted approximately 141,000 share-equivalents to certain employees that vest at the end of a three-year period beginning January 1, 2015, if performance targets based on return on assets of the applicable segment or return on capital employed are certified as being met.  These awards are settled in stock at the time of vesting, with payouts that range from 0 to 200 percent of the target award.  Dividend equivalents are accumulated and paid upon vesting for the number of vested shares.

	ROCEI / ROAI
	Awards (000’s)		Weighted-Average Grant-Date Fair Value of Occidental Stock
Unvested at January 1	158			$	91.90
Granted	141			101.95
Shares issued upon California Resources spin-off	16			—
Shares forfeited by employees of California Resources	(33	)		87.28
Unvested at December 31	282			92.25

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Spin-off of California Resources Corporation

12 Months Ended

Dec. 31, 2014

Spin-off and related activities

Spin-off of California Resources Corporation

NOTE 17SPIN-OFF OF CALIFORNIA RESOURCES CORPORATION

On November 30, 2014, the spin-off of Occidental’s California oil and gas operations and related assets was completed through the distribution of 81.3 percent of the outstanding shares of common stock of California Resources, creating an independent, publicly traded company.  Occidental shareholders at the close of business on the record date of November 17, 2014 received 0.4 shares of California Resources for every share of Occidental common stock held.  Fractional shares of California Resources were not distributed and any fractional shares otherwise issuable to an Occidental shareholder were sold on the open market on such shareholder’s behalf, and such shareholder received a cash payment with respect to the fractional share.

In connection with the spin-off, California Resources distributed to Occidental $4.95 billion in restricted cash and $1.15 billion in unrestricted cash.  Occidental retained 71.5 million shares in California Resources, see Note 14.  The cash distributions were issued using the proceeds from $5 billion in Senior Notes issued by California Resources in October 2014 and borrowings under California Resources’ $1.0 billion Term Loan Facility and $2.0 billion Revolving Credit Facility.  As indicated by a private letter ruling from the Internal Revenue Service (IRS), the $4.95 billion distribution will be used solely to pay dividends, repurchase common stock, repay debt, or a combination of the foregoing, within eighteen months following the distribution.  At December 31, 2014, the remaining balance of the restricted cash distribution was $4.0 billion and was included in the “Restricted cash” line on the consolidated balance sheet.

In order to effect the separation and govern the relationship with California Resources after the spin-off, Occidental and California Resources entered into a Separation and Distribution Agreement, a Stockholder’s and Registration Rights Agreement, a Tax Sharing Agreement, an Employee Matters Agreement, a Transition Services Agreement, an Area of Mutual Interest Agreement, a Confidentiality and Trade Secret Protection Agreement, and an Intellectual Property License Agreement.

The Separation and Distribution Agreement and related ancillary agreements govern the transfer of assets and other matters related to the spin-off.  The Intellectual Property License Agreement governs the allocation of intellectual property rights and assets between California Resources and Occidental.  The Confidentiality and Trade Secret Protection Agreement safeguards confidential and trade information related to Occidental from five years after the spin-off date. The Stockholder’s and Registration Rights Agreement governs, among other things, the registration of shares of California Resources.  The Area of Mutual Interest Agreement governs the rights and obligations of both California Resources and Occidental for the exploration and development of oil and natural gas interests located within the United States excluding California.

The Tax Sharing Agreement governs the respective rights, responsibilities and obligations of California Resources and Occidental with respect to taxes, tax attributes, tax returns, tax proceedings and certain other tax matters.  In addition, the Tax Sharing Agreement imposed certain restrictions on California Resources and its subsidiaries (including restrictions on share issuances, business combinations, sales of assets and similar transactions) that are designed to preserve the tax-free status of the distribution and certain related transactions. The Tax Sharing Agreement sets forth the obligations of California Resources and Occidental as to the filing of tax returns, the administration of tax proceedings and assistance and cooperation on tax matters.

The Employee Matters Agreement governs the compensation and employee benefit obligations with respect to the current and former employees and non-employee directors of California Resources and Occidental, and generally allocates liabilities and responsibilities relating to employee compensation, benefit plans and programs. The Employee Matters Agreement provides that employees of California Resources will no longer participate in benefit plans sponsored or maintained by Occidental. In addition, the Employee Matters Agreement provides that each of the parties will be responsible for their respective current employees and compensation plans for such current employees, and Occidental will be responsible for liabilities relating to former employees who left prior to the separation (other than in certain instances where a plan or program was sponsored by a company that became part of the California Resources group of companies at the separation). The Employee Matters Agreement sets forth the general principles relating to employee matters and also addresses any special circumstances during the transition period. The Employee Matters Agreement also provides that (i) the distribution does not constitute a change in control under existing plans, programs, agreements or arrangements, and (ii) the distribution and the assignment, transfer or continuation of the employment of employees with another entity will not constitute a severance event under the applicable plans, programs, agreements or arrangements.

The Transition Services Agreement sets forth the terms on which Occidental will provide California Resources, and California Resources will provide to Occidental, certain services or functions California Resources and Occidental historically have shared. Transition services include administrative, payroll, human resources, data processing, environmental health and safety, financial audit support, financial transaction support, information technology systems and various other corporate services. The agreement provides for the provision of specified transition services, generally for a period of up to 24 months on a cost or a cost-plus basis.

The following table presents the carrying value of major categories of assets and liabilities of California Resources immediately preceding the spin-off at November 30, 2014 and at December 31, 2013:

(in millions)	November 30, 2014		December 31, 2013
CURRENT ASSETS
Cash and cash equivalents	$	8	$	—
Accounts receivables, net	591		30
Inventories	73		75
Other current assets	22		125
Total current assets	694		230
Total property, plant, and equipment	23,257		21,065
Accumulated depreciation, depletion, and amortization	(8,079)		(6,974)
	15,178		14,091
LONG-TERM RECEIVABLES AND OTHER ASSETS, NET	112		35
TOTAL ASSETS	$	15,984	$	14,356
CURRENT LIABILITIES
Accounts payable	$	696	$	447
Accrued liabilities	182		253
Total current liabilities	878		700
LONG-TERM DEBT, NET	6,295		—
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred domestic and foreign income taxes	3,227		2,904
Other	531		509
	3,758		3,413
TOTAL LIABILITIES	$	10,931	$	4,113

Sales and other operating revenues and income from discontinued operations related to California Resources were as follows:

For the years ended December 31, (in millions)	2014		2013		2012
Sales and other operating revenue from discontinued operations	$	3,951	$	4,285	$	4,072
Income from discontinued operations before-tax	1,205		1,531		1,265
Income tax expense	440		541		459
Income from discontinued operations	$	765	$	990	$	806

XML

LEASE COMMITMENTS (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Future net minimum operating lease payments
Operating lease, 2015	$ 192
Operating lease, 2016	169
Operating lease, 2017	161
Operating lease, 2018	168
Operating lease, 2019	104
Operating lease, Thereafter	592
Total minimum lease payments	1,386
Rental expense for operating leases, net of sublease rental income	155	196	165
Sublease income	$ 4	$ 3	$ 4

XML

Industry Segments (Tables)

12 Months Ended

Dec. 31, 2014

Industry Segments

Industry segment and corporate disclosures (in millions)

Industry Segments
(in millions)							Midstream			Corporate
							and			and
	Oil and Gas			Chemical			Marketing			Eliminations			Total
YEAR ENDED DECEMBER 31, 2014
Net sales	$	13,887	(a)	$	4,817	(b)	$	1,373	(c)	$	(765)		$	19,312
Pretax operating profit (loss)	$	428	(d)	$	420	(e)	$	2,578	(f)	$	(1,871)	(g)	$	1,555
Net income attributable to noncontrolling interest	—			—			(14)			—			(14)
Income taxes	—			—			—			(1,685)		(g)	(1,685)
Discontinued operations, net	—			—			—			760		(i)	760
Net income (loss) attributable to common stock	$	428		$	420		$	2,564		$	(2,796)		$	616
Investments in unconsolidated entities	$	11		$	202		$	948		$	10		$	1,171
Property, plant and equipment additions, net (k)	$	6,589		$	325		$	2,093		$	103		$	9,110
Depreciation, depletion and amortization	$	3,701		$	367		$	160		$	33		$	4,261
Total assets	$	31,072		$	3,917		$	12,283		$	8,987		$	56,259
YEAR ENDED DECEMBER 31, 2013
Net sales	$	15,008	(a)	$	4,673	(b)	$	1,174	(c)	$	(685)		$	20,170
Pretax operating profit (loss)	$	6,411	(d)	$	743	(e)	$	1,523	(f)	$	(531)	(g)	$	8,146
Income taxes	—			—			—			(3,214)		(h)	(3,214)
Discontinued operations, net	—			—			—			971		(i)	971
Net income (loss) attributable to common stock	$	6,411		$	743		$	1,523		$	(2,774)		$	5,903
Investments in unconsolidated entities	$	108		$	34		$	1,307		$	10		$	1,459
Property, plant and equipment additions, net (k)	$	5,456		$	435		$	1,437		$	166		$	7,494
Depreciation, depletion and amortization	$	3,676		$	346		$	149		$	32		$	4,203
Total assets	$	46,213		$	3,947		$	14,374		$	4,909		$	69,443
YEAR ENDED DECEMBER 31, 2012
Net sales	$	14,953	(a)	$	4,580	(b)	$	1,164	(c)	$	(597)		$	20,100
Pretax operating profit (loss)	$	5,840	(d)	$	720		$	440	(f)	$	(512)	(g)	$	6,488
Income taxes	—			—			—			(2,659)		(h)	(2,659)
Discontinued operations, net	—			—			—			769		(i)	769
Net income (loss) attributable to common stock	$	5,840	(d)	$	720		$	440		$	(2,402)		$	4,598
Investments in unconsolidated entities	$	113		$	108		$	1,662		$	11		$	1,894
Property, plant and equipment additions, net (k)	$	6,067		$	365		$	1,451		$	91		$	7,974
Depreciation, depletion and amortization	$	3,065		$	345		$	148		$	27		$	3,585
Total assets	$	44,004		$	3,854		$	12,762		$	3,590		$	64,210

(See footnotes on next page)

Footnotes:

(a) Oil sales represented approximately 90 percent, 91 percent and 91 percent of the oil and gas segment net sales for the years ended December 31, 2014, 2013 and 2012, respectively.

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

Net product sales for the chemical segment

	Basic Chemicals	Vinyls	Other Chemicals
Year ended December 31, 2014	54%	43%	3%
Year ended December 31, 2013	55%	42%	3%
Year ended December 31, 2012	57%	40%	3%

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

Net sales for the midstream and marketing segment

	Gas Processing	Power	Marketing, Trading, Transportation and other
Year ended December 31, 2014	49%	31%	20%
Year ended December 31, 2013	54%	30%	16%
Year ended December 31, 2012	60%	24%	16%

(d) The 2014 amount includes pre-tax charges of $4.7 billion for the impairment of domestic oil and gas assets, pre-tax charges of $1.1 billion for the impairment of foreign oil and gas assets, and pre-tax gain of $531 million for the sale of the Hugoton field. The 2013 amount includes pre-tax charges of $607 million for the impairment of domestic non-producing acreage.  The 2012 amount includes pre-tax charges of $1.7 billion for the impairment of domestic gas assets and related items.

(e) The 2014 amount includes the pre-tax charge of $149 million. The 2013 amount includes a pre-tax gain of $131 million for the sale of an investment in Carbocloro.

(f) The 2014 amount includes pre-tax gains of $633 million and $1,351 million for the sales of BridgeTex Pipeline and a portion of an investment in Plains Pipeline, respectively, and other charges of $31 million. The 2013 amount includes a pre-tax gain of $1,044 million for the sale of a portion of an investment in Plains Pipeline and other items of $58 million.

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

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

(i) Relates to discontinued operations from Ecuador and the spin-off of California Resources.

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

Significant items affecting earnings included in the Corporate segment

Benefit (Charge) (in millions)	2014		2013		2012
CORPORATE
Pre-tax operating profit (loss)
California Resources other than temporary loss	$	(553)	$	—	$	—
Joslyn Impairment	(805)		—		—
Spin-off and other costs	(61)		—		—
Litigation reserves	—		—		(20)
Charge for former executives and consultants	—		(55)		—
	$	(1,419)	$	(55)	$	(20)
Income taxes
Tax effect of pre-tax and other adjustments *	$	927	$	(167)	$	612

*  Amounts represent the tax effect of the pre-tax adjustments listed in this note, as well as those in footnotes (d), (e) and (f).

(k) Includes capital expenditures and capitalized interest, but excludes acquisition and disposition of assets.

Net sales and property, plant and equipment, net by geographic areas

(in millions)	Net sales (a)						Property, plant and equipment, net
For the years ended December 31,	2014		2013		2012		2014		2013		2012
United States	$	11,943	$	11,724	$	11,287	$	26,673	$	42,956	$	40,786
Foreign
Qatar	2,803		2,995		3,356		2,605		2,605		2,676
Oman	2,524		2,567		2,578		2,876		2,509		2,353
Colombia	938		1,022		1,027		1,396		1,259		1,041
United Arab Emirates	—		—		—		4,312		3,131		2,104
Other Foreign	1,104		1,862		1,852		1,868		3,361		3,104
Total Foreign	7,369		8,446		8,813		13,057		12,865		11,278
Total	$	19,312	$	20,170	$	20,100	$	39,730	$	55,821	$	52,064

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

XML

Consolidated Statements of Income (Parenthetical) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
CONSOLIDATED CONDENSED STATEMENTS OF INCOME
Cost of sales, depreciation, depletion and amortization	$ 4,257	$ 4,197	$ 3,578

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

12 Months Ended

Dec. 31, 2014

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

NOTE 1SUMMARY 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 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 and 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 power.  Additionally, the midstream and marketing segment 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 2014 presentation.

As a result of the spin-off of California Resources Corporation (California Resources) the statements of income and cash flows related to California Resources have been treated as discontinued operations for the years ended December 31, 2014, 2013 and 2012. The assets and liabilities of California Resources were removed from Occidental’s consolidated balance sheet as of November 30, 2014.  See Note 17 Spin-off of California Resources for additional information.

INVESTMENTS IN UNCONSOLIDATED ENTITIES

Occidental’s percentage interest in the underlying net assets of affiliates as to which it exercises significant influence without having a controlling interest (excluding oil and gas ventures in which Occidental holds an undivided interest) are accounted for under the equity method.  Occidental reviews equity-method investments for impairment whenever events or changes in circumstances indicate that an other-than-temporary decline in value may have occurred.  The amount of impairment, if any, is based on quoted market prices, when available, or other valuation techniques, including discounted cash flows.

REVENUE RECOGNITION

Revenue is recognized from oil and gas production when title has passed to the customer, which occurs when the product is shipped.  In international locations where oil is shipped by tanker, title passes when the tanker is loaded or product is received by the customer, depending on the shipping terms.  This process occasionally causes a difference between actual production in a reporting period and sales volumes that have been recognized as revenue. Revenues from the production of oil and gas properties in which Occidental has an interest with other producers are recognized on the basis of Occidental’s net revenue interest.

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 expected outcomes as well as 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.  Management believes that these estimates and judgments provide a reasonable basis for the fair presentation of Occidental’s financial statements. Occidental establishes a valuation allowance against net operating losses and other deferred tax assets to the extent it believes the future benefit from these assets will not be realized in the statutory carryforward periods.  Realization of deferred tax assets, including any net operating loss carryforwards, is dependent upon Occidental generating sufficient future taxable income and reversal of temporary differences in jurisdictions where such assets originate.

The accompanying consolidated financial statements include assets of approximately $15 billion as of December 31, 2014, and net sales of approximately $7.3 billion for the year ended December 31, 2014, relating to Occidental’s operations in countries outside North America.  Occidental operates some of its oil and gas business in countries that have experienced political instability, nationalizations, corruption, 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 $3.4 billion and $2.9 billion at December 31, 2014 and 2013, respectively.

RESTRICTED CASH

Restricted cash is the result of the separation of California Resources. As of December 31, 2014, there was $4.0 billion of cash restricted for the payment of dividends, payment of debt or share repurchases. Restricted cash must be used within 18 months of the date of distribution.

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.

A decline in market value of any available-for-sale securities below cost that is deemed to be other-than-temporary results in an impairment to reduce the carrying amount to fair value.  To determine whether an impairment is other-than-temporary, Occidental considers all available information relevant to the investment, including past events and current conditions. Evidence considered in this assessment includes the reasons for the impairment, the severity and duration of the impairment, changes in value subsequent to year-end, and the general market condition in the geographic area or industry the investee operates in.

INVENTORIES

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

For the chemical segment, Occidental’s 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 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	2014			2013			2012
Balance — Beginning of Year	$	140		$	124		$	189
Additions to capitalized exploratory well costs pending the determination of proved reserves	462			337			400
Reclassifications to property, plant and equipment based on the determination of proved reserves	(423		)	(271		)	(389		)
Spin-off of California Resources	(17		)	—			—
Capitalized exploratory well costs charged to expense	(21		)	(50		)	(76		)
Balance — End of Year	$	141		$	140		$	124

Occidental expenses annual lease rentals, the costs of injectants used in production and geological, geophysical and seismic costs as incurred.

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 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.

Occidental performs impairment tests with respect to its proved properties whenever events or circumstances indicate that the carrying value of property may not be recoverable. If there is an indication the carrying amount of the asset may not be recovered due to declines in current and forward prices, significant changes in reserve estimates, changes in management’s plans, or other significant events, management will evaluate the property for impairment. Under the successful efforts method, if the sum of the undiscounted cash flows is less than the carrying value of the proved property, the carrying value is reduced to estimated fair value and reported as an impairment charge in the period. Individual proved properties are grouped for impairment purposes at the lowest level for which there are identifiable cash flows, which is generally on a field by field basis.  The fair value of impaired assets is typically determined based on the present value of expected future cash flows using discount rates believed to be consistent with those used by market participants.  The impairment test incorporates a number of assumptions involving expectations of future cash flows which can change significantly over time.  These assumptions include estimates of future product prices, contractual prices, estimates of risk-adjusted proved oil and gas reserves and estimates of future operating and development costs.  See Note 15 for further discussion of asset impairments.

A portion of the carrying value of Occidental’s oil and gas properties is attributable to unproved properties.  At December 31, 2014, the net capitalized costs attributable to unproved properties were $2.0 billion.  The unproved amounts are not subject to DD&A until they are classified as proved properties. Capitalized costs attributable to the properties become subject to DD&A when proved reserves are assigned to the property.  If the exploration efforts are unsuccessful, or management decides not to pursue development of these properties as a result of lower commodity prices, higher development and operating costs, contractual conditions or other factors, 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.

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 the assets or liabilities; Level 2 – using observable inputs other than quoted prices for the assets or liabilities; and Level 3 – using unobservable inputs.  Transfers between levels, if any, are reported at the end of each reporting period.

Fair Values - Recurring

Occidental primarily applies the market approach for recurring fair value measurements, maximizes its use of observable inputs and minimizes its use of unobservable inputs.  Occidental utilizes the mid-point 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:

· 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 classified as Level 2 and 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 values 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 generally unobservable in the marketplace, or are observable but have been adjusted based upon various assumptions 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 $361 million and $459 million at December 31, 2014 and 2013, respectively.

ENVIRONMENTAL LIABILITIES AND EXPENDITURES

Environmental expenditures that relate to current operations are expensed or capitalized as appropriate.  Occidental records environmental reserves and related charges and expenses 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, 2014, 2013 and 2012, 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 may occur.

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

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

ASSET RETIREMENT OBLIGATIONS

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

At a certain number of its facilities, Occidental has identified conditional asset retirement obligations that are related mainly to plant decommissioning.  Occidental does not know or cannot estimate when it may settle these obligations.  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 $1,024 million and $1,283 million is included in deferred credits and other liabilities - other, with the remaining current portion in accrued liabilities at December 31, 2014 and 2013, respectively.

For the years ended December 31, (in millions)	2014			2013
Beginning balance	$	1,332		$	1,266
Liabilities incurred – capitalized to PP&E	57			101
Liabilities settled and paid	(78		)	(72		)
Accretion expense	69			68
Acquisitions, dispositions and other – changes in PP&E	(11		)	(10		)
Spin-off of California Resources	(399		)	—
Revisions to estimated cash flows – changes in PP&E	121			(21		)
Ending balance	$	1,091		$	1,332

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 lack of correlation between the hedged item and the hedging instrument due to location, quality, grade or changes in the expected quantity of the hedged item.  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, 2014, 2013 and 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.

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 is as follows.

For cash- and stock-settled restricted stock units or incentive award shares (RSUs) and capital employed incentive awards and return on assets (ROCEI/ROAI), compensation value is initially measured on the grant date using the quoted market price of Occidental’s common stock and the estimated payout at the grant date. For total shareholder return incentives (TSRIs), compensation value is initially measured on the grant date using estimated payout levels derived from a Monte Carlo valuation model.  Compensation expense for RSUs, ROCEI/ROAI 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 dividends accrued on unvested awards is adjusted quarterly for any changes in stock price and the number of share equivalents expected to be paid based on the relevant performance and market criteria, if applicable.  All such performance or stock-price-related changes are recognized in periodic compensation expense.  The stock-settled portion of 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 awards are considered participating securities prior to vesting and, therefore, have been deducted from earnings 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, which are more fully described in Note 13, 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 any 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 $2.9 billion, $1.8 billion and $2.3 billion during the years ended December 31, 2014, 2013 and 2012, respectively.  Occidental also paid production, property and other taxes of approximately $610 million, $606 million and $524 million during the years ended December 31, 2014, 2013 and 2012, respectively, substantially all of which was in the United States.  Interest paid totaled approximately $219 million, $238 million and $190 million, net of capitalized interest of $180 million, $137 million and $100 million, for the years 2014, 2013 and 2012, respectively.

FOREIGN CURRENCY TRANSACTIONS

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

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STOCKHOLDERS' EQUITY (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Oct. 02, 2014
Common stock issuances
Balance at the beginning of the year	889,919,058	888,801,000	886,809,000
Issued	584,000	826,000	1,746,000
Options exercised and other, net	55,000	292,000	246,000
Balance at the end of the year	890,557,537	889,919,058	888,801,000
TREASURY STOCK
Share repurchase program, authorized shares				185,000,000
TREASURY STOCK
Shares purchased under share repurchase program	25,800,000	10,300,000
Share repurchase program, average cost per share of shares repurchased during period	$ 93.40	$ 94.42
Treasury stock, shares	119,951,199	93,928,179	83,300,000
NONREDEEMABLE PREFERRED STOCK
Preferred stock, authorized shares	50,000,000	50,000,000	50,000,000
Preferred stock, par value	$ 1.00	$ 1.00	$ 1.00
Preferred stock, outstanding shares	0	0	0
Basic EPS
(Loss) / Income from continuing operations	$ (130,000,000)	$ 4,932,000,000	$ 3,829,000,000
Less: Income from continuing operations attributable to noncontrolling interest	(14,000,000)
(Loss) / Income from continuing operations	(144,000,000)	4,932,000,000	3,829,000,000
Discontinued operations, net	760,000,000	971,000,000	769,000,000
NET INCOME ATTRIBUTABLE TO COMMON STOCK	616,000,000	5,903,000,000	4,598,000,000
Less: Net income allocated to participating securities		(13,000,000)	(8,000,000)
Net income attributable to common stock, net of participating securities	616,000,000	5,890,000,000	4,590,000,000
Weighted average number of basic shares	781,100,000	804,100,000	809,300,000
Basic EPS (in dollars per share)	$ 0.79	$ 7.33	$ 5.67
Diluted EPS
Net income attributable to common stock, net of participating securities	616,000,000	5,890,000,000	4,590,000,000
Weighted average number of basic shares	781,100,000	804,100,000	809,300,000
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements		500,000	700,000
Total diluted weighted average common shares	781,100,000	804,600,000	810,000,000
Earnings Per Share, Diluted	$ 0.79	$ 7.32	$ 5.67
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
Foreign currency translation adjustments	(7,000,000)	(5,000,000)
Unrealized losses on derivatives	(11,000,000)	(14,000,000)
Pension and post-retirement adjustments	(339,000,000)	(284,000,000)
Accumulated other comprehensive income (loss)	$ (357,000,000)	$ (303,000,000)
Subsequent event
TREASURY STOCK
Share repurchase program, increase in authorized shares				60,000,000

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Schedule II - Valuation and Qualifying Accounts

12 Months Ended

Dec. 31, 2014

Schedule II - Valuation and Qualifying Accounts

Schedule II - Valuation and Qualifying Accounts

			Additions
	Balance at Beginning of Period		Charged to Costs and Expenses		Charged to Other Accounts			Deductions (a)			Balance at End of Period
2014
Allowance for doubtful accounts	$	17	$	4	$	(2	)	$	—		$	19
Environmental	$	330	$	79	$	(7	)	$	(68	)	$	334
Litigation, tax and other reserves	166		1		190			(19		)	338
	$	496	$	80	$	183		$	(87	)	$	672	(b)
2013
Allowance for doubtful accounts	$	16	$	1	$	—		$	—		$	17
Environmental	$	344	$	60	$	—		$	(74	)	$	330
Litigation, tax and other reserves	229		3		4			(70		)	166
	$	573	$	63	$	4		$	(144	)	$	496	(b)
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)

Note:  The amounts presented represent continuing operations.

(a)Primarily represents payments.

(b)Of these amounts, $287 million, $101 million and $98 million in 2014, 2013 and 2012, respectively, are classified as current.

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Retirement and Postretirement Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2014

Retirement and Postretirement Benefit Plans

Components of amounts recognized in the consolidated balance sheets (in millions)

(in millions)	Pension Benefits				Postretirement Benefits
As of December 31,	2014		2013		2014		2013
Amounts recognized in the consolidated balance sheet:
Other assets	$	57	$	104	$	—	$	—
Accrued liabilities	(6)		(6)		(57)		(58)
Deferred credits and other liabilities — other	(68)		(83)		(980)		(958)

After-tax balances included in AOCI (in millions)

AOCI included the following after-tax balances:
Net loss	$	83	$	66	$	255	$	225
Prior service cost	—		1		1		2
	$	83	$	67	$	256	$	227

Funding status of Occidental's plans (in millions)

For the years ended December 31,
Changes in the benefit obligation:
Benefit obligation — beginning of year	$	523	$	615	$	1,016	$	1,127
Service cost — benefits earned during the period	11		13		24		29
Interest cost on projected benefit obligation	23		24		44		43
Actuarial (gain) loss	53		(35)		83		(126)
Foreign currency exchange rate (gain) loss	(9)		(5)		—		—
Spin-off of California Resources	(105)		—		(72)		—
Benefits paid	(43)		(54)		(59)		(57)
Settlements	—		(35)		—		—
Benefit obligation — end of year	$	453	$	523	$	1,036	$	1,016
Changes in plan assets:
Fair value of plan assets — beginning of year	$	538	$	499	$	—	$	—
Actual return on plan assets	24		88		—		—
Employer contributions	7		29		—		—
Spin-off of California Resources	(90)		—		—		—
Benefits paid	(43)		(54)		—		—
Settlements	—		(24)		—		—
Fair value of plan assets — end of year	$	436	$	538	$	—	$	—
Funded/(Unfunded) status:	$	(17)	$	15	$	(1,036)	$	(1,016)

Schedule of projected benefit obligation, accumulated benefit obligation and fair value of plan assets for defined benefit pension plans with an accumulated benefit obligation in excess of plan assets and plan assets in excess of the accumulated benefit obligation

(in millions)	Accumulated Benefit Obligation in Excess of Plan Assets				Plan Assets in Excess of Accumulated Benefit Obligation
As of December 31,	2014		2013		2014		2013
Projected Benefit Obligation	$	173	$	122	$	280	$	401
Accumulated Benefit Obligation	$	168	$	112	$	280	$	386
Fair Value of Plan Assets	$	100	$	39	$	336	$	499

Components of the net periodic benefit cost (in millions)

	Pension Benefits						Postretirement Benefits
For the years ended December 31, (in millions)	2014		2013		2012		2014		2013		2012
Net periodic benefit costs:
Service cost — benefits earned during the period	$	11	$	13	$	13	$	24	$	29	$	25
Interest cost on projected benefit obligation	23		24		27		44		43		42
Expected return on plan assets	(33)		(31)		(31)		—		—		—
Recognized actuarial loss	6		19		19		20		38		37
Other costs and adjustments	(8)		(13)		17		1		1		1
Net periodic benefit cost	$	(1)	$	12	$	45	$	89	$	111	$	105

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,	2014		2013	2014	2013
Benefit Obligation Assumptions:
Discount rate	3.81%		4.45%	3.99%	4.75%
Rate of compensation increase	—	(a)	4.00%	—	—
Net Periodic Benefit Cost Assumptions:
Discount rate	4.45%		3.59%	4.75%	3.89%
Assumed long term rate of return on assets	6.50%		6.50%	—	—
Rate of compensation increase	4.00%	(a)	4.00%	—	—

(a) Plans requiring a salary increase assumption were separated with California Resources.

Fair values of Occidental's pension plan assets by asset category (in millions)

(in millions)	Fair Value Measurements at December 31, 2014 Using
Description	Level 1		Level 2		Level 3		Total
Asset Class:
U.S. government securities	$	15	$	—	$	—	$	15
Corporate bonds (a)	—		76		—		76
Common/collective trusts (b)	—		13		—		13
Mutual funds:
Bond funds	42		—		—		42
Blend funds	68		—		—		68
Common and preferred stocks (c)	196		—		—		196
Other	—		38		1		39
Total pension plan assets (d)	$	321	$	127	$	1	$	449

(in millions)	Fair Value Measurements at December 31, 2013 Using
Description	Level 1		Level 2		Level 3		Total
Asset Class:
U.S. government securities	$	16	$	—	$	—	$	16
Corporate bonds (a)	—		84		—		84
Common/collective trusts (b)	—		19		—		19
Mutual funds:
Bond funds	64		—		—		64
Blend funds	105		—		—		105
Value and growth funds	6		—		—		6
Common and preferred stocks (c)	201		—		—		201
Other	—		37		11		48
Total pension plan assets (d)	$	392	$	140	$	11	$	543

(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 $13 million and $5 million as of December 31, 2014 and 2013, respectively.

Estimated future benefit payments, which reflect expected future service, as appropriate

For the years ended December 31, (in millions)	Pension Benefits		Postretirement Benefits
2015	$	38	$	58
2016	$	37	$	59
2017	$	33	$	59
2018	$	32	$	59
2019	$	32	$	60
2020— 2024	$	191	$	304

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STOCKHOLDERS' EQUITY

12 Months Ended

Dec. 31, 2014

STOCKHOLDERS' EQUITY

STOCKHOLDERS' EQUITY

NOTE 11STOCKHOLDERS’ EQUITY

The following is a summary of common stock issuances:

Shares in thousands	Common Stock
Balance, December 31, 2011	886,809
Issued	1,746
Options exercised and other, net	246
Balance, December 31, 2012	888,801
Issued	826
Options exercised and other, net	292
Balance, December 31, 2013	889,919
Issued	584
Options exercised and other, net	55
Balance, December 31, 2014	890,558

TREASURY STOCK

On October 2, 2014, Occidental increased the total number of shares authorized for its share repurchase program by 60 million shares to 185 million shares total; however, the program does not obligate Occidental to acquire any specific number of shares and may be discontinued at any time.  In 2014 and 2013, respectively, Occidental purchased 25.8 million and 10.3 million shares under the program at an average cost of $93.40 and $94.42 per share, respectively. Additionally, Occidental purchased shares from the trustee of its defined contribution savings plan during each year. As of December 31, 2014, 2013 and 2012, treasury stock shares numbered 120.0 million, 93.9 million and 83.3 million, respectively.

NONREDEEMABLE PREFERRED STOCK

Occidental has authorized 50,000,000 shares of preferred stock with a par value of $1.00 per share.  At December 31, 2014, 2013 and 2012, Occidental had no outstanding shares of preferred stock.

EARNINGS PER SHARE

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

(in millions, except per-share amounts)	2014			2013			2012
Basic EPS
(Loss) / Income from continuing operations	$	(130	)	$	4,932		$	3,829
Less: Income from continuing operations attributable to noncontrolling interest	(14		)	—			—
(Loss) / Income from contributing operations attributable to common stock	(144		)	4,932			3,829
Discontinued operations, net	760			971			769
Net income	616			5,903			4,598
Less: Net income allocated to participating securities	—			(13		)	(8		)
Net income, net of participating securities	$	616		$	5,890		$	4,590
Weighted average number of basic shares	781.1			804.1			809.3
Basic EPS	$	0.79		$	7.33		$	5.67
Diluted EPS
Net income, net of participating securities	$	616		$	5,890		$	4,590
Weighted average number of basic shares	781.1			804.1			809.3
Dilutive securities	—			0.5			0.7
Total diluted weighted average common shares	781.1			804.6			810.0
Diluted EPS	$	0.79		$	7.32		$	5.67

ACCUMULATED OTHER COMPREHENSIVE LOSS

Accumulated other comprehensive loss consisted of the following after-tax amounts:

Balance at December 31, (in millions)	2014			2013
Foreign currency translation adjustments	$	(7	)	$	(5	)
Unrealized losses on derivatives	(11		)	(14		)
Pension and post-retirement adjustments (a)	(339		)	(284		)
Total	$	(357	)	$	(303	)

(a) See Note 13 for further information.