UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form 10-K
þ Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
 
¨ Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the fiscal year endedDecember 31, 20132016 For the transition period from                to

Commission File Number 1-9210

Occidental Petroleum Corporation
(Exact name of registrant as specified in its charter)

State or other jurisdiction of incorporation or organization Delaware
I.R.S. Employer Identification No. 95-4035997
Address of principal executive offices 10889 Wilshire Blvd., Los Angeles, CA5 Greenway Plaza, Suite 110, Houston, Texas
Zip Code 9002477046
Registrant's telephone number, including area code (310) 208-8800(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, $0.20 par value New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.      Yes 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 FilerþAccelerated 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 $70.6$57.5 billion, computed by reference to the closing price on the New York Stock Exchange composite tape of $89.23$75.56 per share of Common Stock on June 30, 2013.2016. 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, 2014,2017, there were 794,747,955764,291,301 shares of Common Stock outstanding.outstanding, par value $0.20 per share.

DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant’s definitive Proxy Statement, relating to its May 2, 201412, 2017 Annual Meeting of Stockholders, are incorporated by reference into Part III.



TABLE OF CONTENTS
 
  Page
Part I  
Items 1 and 2
Business and Properties...................................................................................................................................................................................................................................................................................................................
3
 
General...........................................................................................................................................................................................................................................................................................................................................................
3
 
Oil and Gas Operations.........................................................................................................................................................................................................................................................................................................
3
 
Chemical Operations.................................................................................................................................................................................................................................................................................................................
4
 
Midstream Marketing and OtherMarketing Operations...................................................................................................................................................................................................................................................
5
 
Capital Expenditures.........................................................................................................................................................
56
 
Employees.................................................................................................................................................................................................................................................................................................................................................
56
 
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.......................................................................................................................................................................................................................................................................................................................................
89
Part II  
Item 5
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.............................
910
Item 6
Selected Financial Data..........................................................................................................................................................
1112
Item 7 and 7A
Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A).....................................
1112
 
Strategy.............................................................................................................................................................................
1213
 
Oil and Gas Segment........................................................................................................................................................
14
 
Chemical Segment............................................................................................................................................................
20
 
Midstream Marketing and OtherMarketing Segment..........................................................................................................................................................................................................................................................
2120
 
Segment Results of Operations......................................................................................................................................... and Significant Items Affecting Earnings........................................................................
22
Significant Items Affecting Earnings..................................................................................................................................
2521
 
Taxes.................................................................................................................................................................................
2526
 
Consolidated Results of Operations...................................................................................................................................................................................................................................................................
26
 
Consolidated Analysis of Financial Position......................................................................................................................
2728
 
Liquidity and Capital Resources...............................................................................................................................................................................................................................................................................
2728
 
Off-Balance-Sheet Arrangements...........................................................................................................................................................................................................................................................................
2930
 
Contractual Obligations.....................................................................................................................................................
30
 
Lawsuits, Claims and Contingencies.................................................................................................................................................................................................................................................................
30
 
Environmental Liabilities and Expenditures.............................................................................................................................................................................................................................................
31
 
Foreign Investments...................................................................................................................................................................................................................................................................................................................
32
 
Critical Accounting Policies and Estimates...............................................................................................................................................................................................................................................
32
 
Significant Accounting and Disclosure Changes...............................................................................................................
35
Derivative Activities and Market Risk.................................................................................................................................
36
 
Safe Harbor Discussion Regarding Outlook and Other Forward-Looking Data................................................................
3836
Item 7A
Quantitative and Qualitative Disclosures About Market Risk..................................................................................................
36
Item 8
Financial Statements and Supplementary Data...........................................................................................................................................................................................................................................
39
Management's Annual Assessment of and Report on Internal Control Over Financial Reporting....................................
3938
 
Report of Independent Registered Public Accounting Firm on Consolidated Financial Statements.................................
4038
 
Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting.......................
4139
 
Consolidated Balance Sheets...........................................................................................................................................
4240
 
Consolidated Statements of Income..................................................................................................................................Operations...........................................................................................................................
4442
 
Consolidated Statements of Comprehensive Income.......................................................................................................
4543
 
Consolidated Statements of Stockholders' Equity.............................................................................................................
4544
 
Consolidated Statements of Cash Flows.....................................................................................................................................................................................................................................................
4645
 
Notes to Consolidated Financial Statements.........................................................................................................................................................................................................................................
4746
 
Quarterly Financial Data (Unaudited)................................................................................................................................
7677
 
Supplemental Oil and Gas Information (Unaudited)...................................................................................................................................................................................................................
7879
 
Financial Statement Schedule:
 
 
Schedule II – Valuation and Qualifying Accounts..............................................................................................................
9095
Item 9
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure...................................................................................................
9196
Item 9A
Controls and Procedures.................................................................................................................................................................................................................................................................................................................
9196
Management's Annual Assessment of and Report on Internal Control Over Financial Reporting....................................
96
 
Disclosure Controls and Procedures.................................................................................................................................
9196
Item 9B
Other Information....................................................................................................................................................................
96
Part III  
Item 10
Directors, Executive Officers and Corporate Governance......................................................................................................
9197
Item 11
Executive Compensation........................................................................................................................................................
9197
Item 12
Security Ownership of Certain Beneficial Owners and Management..................................................................................... ....................................................................................
9197
Item 13
Certain Relationships and Related Transactions and Director Independence...............................................................................................................................................
9197
Item 14
Principal AccountantAccounting Fees and Services.................................................................................................................................................................................................................................................................
9197
Part IV  
Item 15
Exhibits and Financial Statement Schedules...................................................................................................................................................................................................................................................
9297



Part I

ITEMS 1 AND 2BUSINESS AND PROPERTIES
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 10889 Wilshire Boulevard, Los Angeles, California 90024;5 Greenway Plaza, Suite 110, Houston, Texas 77046; telephone (310) 208-8800.(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 (NGL)(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 other commodities.capacity. Additionally, the midstream and marketing segment invests in entities that conduct similar activities.
For information regarding Occidental's segments, geographic areas of operation and current developments, including its recent strategic reviewstrategies 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 upstream oil and gas operations are located in California, Colorado, Kansas, New Mexico North Dakota, Oklahoma and Texas. International operations are located in Bahrain, Bolivia, Colombia, Iraq, Libya, Oman, Qatar and the United Arab Emirates (UAE).

Proved Reserves and Yemen.  
ProvedReservesandSalesVolumes
The table below shows Occidental’s total oil, NGLs and natural gas proved reserves and sales volumes in 2013, 20122016, 2015 and 2011.2014. 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.

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.



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.
 2013 2012 2011  2016 2015 
2014 (a)
 
Proved Reserves Oil NGLs Gas BOE
(a) 
Oil NGLs Gas BOE
(a) 
Oil NGLs Gas BOE
(a) 
 Oil NGLs Gas BOE
(b) 
Oil NGLs Gas BOE
(b) 
Oil NGLs Gas BOE
(b) 
United States 1,665
 274
 2,855
 2,415
 1,567
 216
 2,889
 2,265
 1,526
 225
 3,365
 2,313
  960
 219
 1,045
 1,353
 915
 186
 1,019
 1,271
 1,273
 222
 1,714
 1,781
 
International 482
 134
 2,711
 1,068
 469
 116
 2,679
 1,031
 482
 55
 1,958
 863
  397
 201
 2,729
 1,053
 394
 144
 2,349
 929
 497
 140
 2,413
 1,038
 
Total 2,147
 408
 5,566
 3,483
 2,036
 332
 5,568
 3,296
 2,008
 280
 5,323
 3,176
  1,357
 420
 3,774
 2,406
 1,309
 330
 3,368
 2,200
 1,770
 362
 4,127
 2,819
 
Sales Volumes                                                  
United States 97
 28
 289
 173
 93
 27
 300
 170
 84
 25
 285
 156
  69
 19
 132
 110
 73
 20
 155
 119
 67
 20
 173
 116
 
International 75
 3
 163
 105
 78
 3
 170
 110
 80
 4
 162
 111
  74
 11
 217
 121
 86
 7
 205
 127
 74
 2
 158
 102
 
Total 172
 31
 452
 278
 171
 30
 470
 280
 164
 29
 447
 267
  143
 30
 349
 231
 159
 27
 360
 246
 141
 22
 331
 218
 
Note: The detailed proved reserves information presented in accordance with Item 1202(a)(2) to Regulation S-K under the Securities Exchange Act of 1934 (Exchange Act) is provided on pages 78-81.under the heading "Supplemental Oil and Gas Information". Proved reserves are stated on a net basis after applicable royalties.
(a)Excludes proved reserves and sales volumes for Occidental's California oil and gas operations, which were transferred to California Resources Corporation (California Resources) in November 2014, and has been treated as discontinued operations.
(b)Natural gas volumes have beenare converted to BOE based on energy content ofat six thousand cubic feet (Mcf) of gas toper 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 2013,2016, the average prices of West Texas Intermediate (WTI) oil and New York Mercantile Exchange (NYMEX) natural gas were $97.97$43.32 per barrel and $3.66$2.42 per Mcf, respectively, resulting in an oil to gas ratio of over 25.18 to 1.


3


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



CHEMICAL OPERATIONS
General
OxyChem owns and operates manufacturing plants at 2223 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. During 2013In early 2014, OxyChem, sold its interest inthrough a Brazilian50/50 joint venture.venture with Mexichem S.A.B. de C.V., broke ground on a 1.2 billion pound-per-year ethylene cracker at the OxyChem expectsIngleside facility. The cracker remains on budget and on schedule and is expected to begin operating in early 2017. OxyChem has announced a 182,000-ton-per-year chlor-alkali$145 million expansion of its manufacturing plant in Tennessee during early 2014.Geismar, Louisiana. The project will produce an OxyChem patented new raw material used in making next-generation, climate-friendly refrigerants with a low global warming and
ozone depletion potential. Construction work has begun with an anticipated completion date in late 2017.

Competition
OxyChem competes with numerous other domestic and foreign chemical producers. For every product it manufactures and markets, OxyChem’s market position was first or second in the United States in 2013.2016 for the principal basic chemical’s products it manufactures and markets as well as for Vinyl Chloride Monomer (VCM). OxyChem ranks in the top three producers of Poly Vinyl Chloride (PVC) in the United States. 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 3.6 million tons
Caustic soda Pulp, paper and aluminum production 3.83.7 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



4



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. In marketing its own and third-party production in the oil and gas business, Occidental strives to maximize realized value using its assets, including transportation and storage capacity. Other midstream and marketing operations also support Occidental's domestic and international oil and gas and chemical operations and include limited commodity trading.operations. Occidental's marketing and trading business competes with other market participants on exchangesexchange platforms and through other bilateral transactions.transactions with direct counterparties. Occidental maximizes the value of its transportation and storage assets by marketing its own and third-party production in the oil and gas business.



The midstream and marketing operations are conducted in the locations described below:
Location Description Capacity
Gas Plants    
California, Texas, New Mexico and Colorado 
Occidental-Occidental and third-party-operated natural gas gathering, compression and processing systems, and CO2 processing and capturing
 3.1 billion cubic feet2.5 Bcf per day
Texas50/50 non-controlling interest in gas processing facility (cryogenic plant with acid gas treating capability)0.2 Bcf per day
United Arab EmiratesNatural gas processing facilities for Al Hosn Gas1.1 Bcf per day
Pipelines    
Texas, New Mexico, and Oklahoma Common carrier oil pipeline and storage system 
616,000720,000 barrels of oil per day
5.87.1 million barrels of oil storage
2,8002,900 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 feetBcf per day
Dolphin Pipeline - Qatar and United Arab Emirates Equity investment in a natural gas pipeline 
3.2 billion cubic feetBcf 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 
18,20019,200 miles of pipelineactive crude oil and NGL pipelines and gathering systems (b)systems.(a)
Storage for 121142 million barrels of crude oil, and other petroleumrefined products and NGL storage capacity and
97 billion cubic feetBcf of natural gas (b)storage working capacity.(a)
Marketing and Trading
Ingleside Crude Terminal    
Texas Connecticut, United Kingdom, Singapore and other Trades around its assets, including transportationOil pipeline, terminal, and storage capacity, and purchases, markets and trades oil, NGLs, gas, power and other commoditiessystem Not applicable
300,000 barrels of oil per day
2.1 million barrels of oil storage
Power Generation    
California, Texas and Louisiana Occidental-operated power and steam generation facilities 
1,8001,200 megawatts per hourand 1.81.6 million pounds of steam per hour
(a)Pipeline currently transports 2.3 Bcf per day. Additional gas compression and customer contracts are required to reach capacity.
(b)Amounts are gross, including interests held by third parties.



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


EMPLOYEES
Occidental employed approximately 12,90011,000 people at December 31, 2013, 9,0002016, 7,000 of whom were located in the United States. Occidental employed approximately 8,5007,000 people in the oil and gas and midstream and marketing segments and 3,1003,000 people in the chemical segment. An additional 1,3001,000 people were employed in administrative and headquarters functions. Approximately 800 U.S.-


5


based700 U.S.-based employees and 1,2001,000 foreign-based employees are represented by labor unions.
Occidental has a long-standing strict policy to provide fair and equal employment opportunities to all applicants and employees.

ENVIRONMENTAL REGULATION
For environmental regulation information, including associated costs, see the information under the heading "Environmental Liabilities and Expenditures" in the MD&A section of this report and "Risk Factors."

AVAILABLEAVAILABLE INFORMATION
Occidental makes the following information available free of charge on its website at www.oxy.com:
ØForms 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);
ØOther SEC filings, including Forms 3, 4 and 5; and
ØCorporate governance information, including its corporate governance guidelines,Corporate Governance Policies, board-committee charters and Code of Business Conduct. (See Part III, Item 10, of this report for further information.)
Information contained on Occidental's website is not part of this report.

ITEM 1A    RISK FACTORS
Volatile global and local commodity pricing strongly affectsaffect Occidental’s results of operations.
Occidental’sOccidental'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.
ChangesPrices 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 consumption patterns,the future. Prolonged or further declines in crude oil, natural gas and NGLs prices would continue to 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 (particularly for gas) economic conditions, inventory levels, production disruptions, the actionsmarket forces which are not in Occidental's control. These factors include, among others:

ØWorldwide and domestic supplies of, and demand for, crude oil, natural gas, NGLs and refined products.
ØThe cost of exploring for, developing, producing, refining and marketing crude oil, natural gas, NGLs and refined products.
ØOperational impacts such as production disruptions, technological advances and regional market conditions, including available transportation capacity and infrastructure constraints in producing areas.
ØChanges in weather patterns and climatic changes.
ØThe impacts of the members of OPEC and other producing nations that may agree to and maintain production levels.
ØThe 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.
ØThe price and availability of alternative and competing fuels.
ØDomestic and foreign governmental regulations and taxes.
ØAdditional or increased nationalization and expropriation activities by foreign governments.
ØGeneral economic conditions worldwide.

The long-term effects of OPEC, currency exchange rates, worldwide drilling and exploration activities, technological developments, weather, geophysical and technical limitations, transportation bottlenecksthese and other matters affectconditions on the supplyprices of crude oil, natural gas, NGLs and demand dynamicsrefined products are uncertain. Generally, Occidental's practice 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 NGLs, which, along withrefined products in the effectfuture.
Global economic and political conditions have driven oil and gas prices down significantly since 2014. These conditions may continue for an extended period. Declines in commodity prices could require Occidental to reduce capital spending and impair the carrying value of changes in market perceptions, contribute to price unpredictability and volatility.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 potential restructuring activities may affect its stock price.
Occidental has disclosed that it is performing a strategic review of its operations, which may result in a restructuring of its business activities. The outcome of this activity 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. Additionally, the restructuring activity may be viewed negatively by the market and result in a stock price drop.
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 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:
ØnewNew 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;products.
ØrefusalRefusal of, or delay in, the extension or grant of exploration, development or production contracts; andcontracts.
ØdevelopmentDevelopment delays and cost overruns due to approval delays for, or denial of, drilling and other permits.permits and authorizations.
In addition, 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 occasionally 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.


6


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;years and the more recent significant decline in crude 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 estimates 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, assumptions concerning future crude oil and natural gas prices, future operating costs and capital expenditures, as well as capitalassumed effects of regulation by governmental agencies. The procedures and operating costs.methods for estimating the reserves by our internal engineers were reviewed by independent petroleum consultants; however, there are inherent uncertainties in estimating reserves. Actual production, revenues, and expenditures with respect to our reserves may vary from estimates, and the variance may be material. If Occidental were required to make significant negative reserve revisions, its results of operations and stock price could be adversely affected. In addition, the discounted cash flows included in this Form 10-K should not be construed as the fair value of the reserves attributable to our properties. The estimated discounted future net cash flows from proved reserves are based on an unweighted 12-month average first-day-of-the-month prices in accordance with SEC regulations. Actual future prices and costs may differ materially from SEC regulation-compliant prices used for purposes of estimating future discounted net cash flows from proved reserves.

Concerns about climate change and further regulation of greenhouse gas emissions may adversely affect Occidental’s operations.operations or results.
The U.S. federal governmentContinuing political and social attention to the stateissue of California have adopted,climate change has resulted in both existing and pending international agreements and national, regional and local legislation and regulatory programs to reduce greenhouse gas emissions. These and other jurisdictions are considering, legislation, regulationsgovernment actions relating to greenhouse gas emissions could require Occidental to incur increased operating and maintenance costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or policies that seek to controlcomply with new regulatory or reduce the production, usereporting requirements, or emissions of “greenhouse gases” (GHG), to control or reduce the production or consumption of fossil fuels, and to increasethey could promote the use of renewablealternative sources of energy and thereby decrease demand for oil, natural gas and other products that Occidental’s businesses produce. Any such legislation or alternative energy sources. For example, California’s GHG cap-and-trade program currently appliesregulatory programs could also increase the cost of consuming, and thereby reduce demand for, oil, natural gas and other products produced by Occidental’s businesses. Consequently, government actions designed to Occidental's operations in the state. The U.S. Environmental Protection Agency has begun to regulate certain GHGreduce emissions from both stationaryof greenhouse gases could have an adverse effect on Occidental’s business, financial condition and mobile sources. The uncertain outcome and timingresults of existing and proposed international, national and state measures make itoperations.
It is difficult to predict their business impact. However,the timing and certainty of such government actions and the ultimate effect on Occidental, which could face risksdepend on, among other things, the type and extent of project execution, increasedgreenhouse gas reductions required, the availability and price of emissions allowances or credits, the availability and price of alternative fuel sources, the energy sectors covered, and Occidental’s ability to recover the costs incurred through its operating agreements or the pricing of the company’s oil, natural gas and taxes and lower demand for and restrictions or prohibition on the use of its products as a result of ongoing GHG reduction efforts.other products.




Occidental’s businesses may experience catastrophic events.
The occurrence of events such as earthquakes, hurricanes, floods, droughts, earthquakes or other acts of nature, well blowouts, fires, explosions, chemical releases, crude oil releases, material or mechanical failure, 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
Cyber-attacks could significantly affect Occidental.
Cyber attacksCyber-attacks on businesses have escalated in recent years. Occidental relies on electronicdigital systems, related infrastructure, technologies and networks to run its business and to control and manage its oil and gas, chemicals, tradingmarketing and pipeline operationsoperations.  Use of the internet, cloud services and other public networks exposes Occidental’s business to cyber-attacks that attempt to gain unauthorized access to data and systems, release confidential information, corrupt data and disrupt critical systems and operations.  Even though Occidental has implemented controls and multiple layers of security to mitigate the risks of a cyber-attack, there can be no assurance that such cyber attack. If, however, Occidental were to experience an attack and its security measures failed,will be sufficient to prevent security breaches from occurring. While we have experienced cyber-attacks in the past, we have not suffered any material losses.  However, if in the future our cyber security measures are compromised or prove insufficient, the potential consequences to itsOccidental’s businesses and the communities in which it operates could be significant.  As cyber-attacks continue to evolve in magnitude and sophistication, we may be required to expend additional resources in order to continue to enhance our cyber security measures and to investigate and remediate any digital systems, related infrastructure, technologies, and network security vulnerabilities.

Occidental's oil and gas reserve additions may not continue at the same rate and its measure of full cycle cash margina failure to replace reserves may not be fully comparable to that of other companies.negatively affect our business.
Unless we conduct successful exploration or development activities, acquire properties containing proved reserves, or both, proved reserves will generally decline. Management expects improved recovery, extensions and discoveries to continueas 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.  Occidental uses a measure referred to as full cycle cash margin to measure its performance in developing reserves at a profitable cost.  The measure may not include all the costs associated with exploration and development related to reserves added for the period, or may include costs related to reserves added or to be added in other periods, and may differ from the calculations used by other companies. 

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," "— Derivative ActivitiesQuantitative 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.


7


ITEM 1BUNRESOLVED STAFF COMMENTS
Occidental has no unresolved SEC staff comments that have been outstanding more than 180 days at December 31, 2013.None.

ITEM 3    LEGAL PROCEEDINGS
The California Air Resources Board assertedIn the fourth quarter of 2014, the U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration sent a claim dated July 23, 2013, againstnotice to an OPC subsidiary regarding reportingthat it is seeking penalties of $165,900 related to a routine, comprehensive inspection of the subsidiary's records, procedures and emissions from four pieces of equipment at its facility in Long Beach, California.facilities, covering a multi-year period. The subsidiary contested the penalties and is evaluating the claim. Although this matter isawaiting a reportable
decision.
 
event,In the financial impactthird 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 expectedseeking penalties of $165,600 related to be insignificant.a crude oil pipeline incident in Scurry County, Texas. The subsidiary contested the penalties and is awaiting a decision.
For information regarding other legal proceedings, see the information under the caption "Lawsuits, Claims and Other Contingencies" in the MD&A section of this report and in Note 9 to the Consolidated Financial Statements.

ITEM 4    MINE SAFETY DISCLOSURES
Not applicable.






EXECUTIVE OFFICERS

The current term of employmentoffice of each executive officer of Occidental will expire at the May 2, 2014, organizational12, 2017 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
March 3, 2014February 23, 2017
 Positions with Occidental and Subsidiaries and Employment History
     
Stephen I. Chazen67
Vicki Hollub
Chief Executive Officer since 2011 and President since 2007; 2010-2011, Chief Operating Officer; 1999-2010, Chief Financial Officer; Director since 2010.

 
William E. Albrecht62Vice President since 2008; Occidental Oil and Gas Corporation (OOGC): President — Oxy Oil & Gas, Americas since 2011; OOGC: President — Oxy Oil & Gas, USA 2008-2011.
Edward A. "Sandy" Lowe62Vice President since 2008; OOGC: President — Oxy Oil & Gas, International Production since 2009; 2008-2009, Executive Vice President — Oxy Oil & Gas, International Production and Engineering.
Willie C.W. Chiang53Executive Vice President, Operations since 2012; ConocoPhillips: 2011-2012, Senior Vice President, Refining, Marketing, Transportation and Commercial; 2008-2011, Senior Vice President, Refining, Marketing and Transportation.
Vicki A. Hollub5457 
Vice President, Chief Executive Officer and Director since 2013; OOGC:April 2016; President, Chief Operating Officer and Director, 2015-2016; Senior Executive Vice President —and President, Oxy Oil &and Gas, U.S. Operations since 2013; 2012-2013,2015; Executive Vice President —and President Oxy Oil &and Gas - Americas, 2014-2015; Vice President and Executive Vice President, U.S. Operations, Oxy Oil and Gas, 2013-2014; Executive Vice President - California Operations; 2011-2012, President & General Manager ofOperations, 2012-2013; Oxy Permian CO2; 2009-2011, Operations President and General Manager, of Oxy Permian.2011-2012.
     
     
B. Chuck Anderson
Joseph C. Elliott
Senior Vice President

 5459 Senior Vice President since 2012;December 2016; President of Occidental Chemical Corporation- Oxy Oil & Gas Domestic since 2006.June 2015; President and General Manager - Permian Resources Midland, 2014-2015; Manager Operations/Well Construction - Permian Resources, 2013-2014; Manager Operations - South Texas, 2011-2013.
     
     
Cynthia L. Walker
Edward A. “Sandy” Lowe
Executive Vice President
 3765 Executive Vice President and Chief Financial Officer since 2012; Goldman, Sachs2015; Group Chairman - Middle East since 2016; Senior Vice President, 2008-2015; President - Oxy Oil & Co.: 2010-2012, Managing Director; 2005-2010, Vice President.Gas International, 2009-2016.
     
     
James
Glenn M. LienertVangolen
Senior Vice President
 6158 Senior Vice President - Business Support since February 2015; Executive Vice President —- Business Support, since 2012; 2010-2012, Executive2014-2015; Senior Vice President and Chief Financial Officer; 2006-2010, Executive Vice President — Finance and Planning.- Oxy Oil & Gas Middle East, 2010-2014.
     
     
Marcia E. Backus
Senior Vice President

 5962 Senior Vice President, General Counsel and Chief Compliance Officer since December 2016; Senior Vice President, General Counsel, Chief Compliance Officer and Corporate Secretary, 2015-2016; Vice President, General Counsel and Corporate Secretary, 2014-2015; Vice President and General Counsel, since 2013;2013-2014; Vinson & Elkins: 1990-2013, Partner.Partner, 1990-2013.
     
     
Roy Pineci
Christopher G. Stavros
Senior Vice President

 5153 Senior Vice President Controller and Principal Accountingsince 2015; Chief Financial Officer since 2008.2014; Executive Vice President, 2014-2015; Vice President, Investor Relations and Treasurer, 2012-2014; Vice President, Investor Relations, 2006-2012.
     
     
Donald P. de Brier
Jennifer M. Kirk
Vice President
 7342 Corporate Executive Vice President, Controller and Corporate SecretaryPrincipal Accounting Officer since 2012; 1993-2012, Executive Vice President, General Counsel2014; Controller, Occidental Oil and Secretary.Gas Corporation, 2012-2014; Finance Director, 2008-2012.
     



8


Part II

ITEM 5MARKET 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 30,00026,000 stockholders of record at DecemberJanuary 31, 2013,2017, and by approximately 648,000700,000 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 dividendsDividends declared on the common stock were $0.64$0.75 for eachthe first and second quarter of 20132016 and $0.76 for the third and fourth quarter ($2.563.02 for the year). On February 13, 2014,16, 2017, a quarterly dividend of $0.72$0.76 per share was declared on the common stock, payable on April 15, 201414, 2017, to stockholders of record on March 10, 2014.2017. The current annual dividend rate of $3.04 per share has increased by over 500 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.

SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS
All of Occidental's stock-based compensation plans for its employees and non-employee directors have been approved by the stockholders. The aggregate number of shares of Occidental common stock authorized for issuance under such plans is approximately 6635 million,, of which approximately 164.5 million had been issuedreserved for issuance through December 31, 2013.2016. The following is a summary of the securities available for issuance under such plans:
a)Number of securities to be issued upon exercise of outstanding options, warrants and rights b)Weighted-average exercise price of outstanding options, warrants and rights c)Number of securities remaining available for future issuance under equity compensation plans (excluding securities in column (a))
        
2,048,6956,220,291  (1)
 
42.1179.98 (2)
 
19,564,60525,267,667 (3)
(1)Includes shares reserved to be issued pursuant to stock options (Options), stock appreciation rights (SARs) and performance-based awards. Shares for performance-based awards are included assuming maximum payout, but may be paid out at lesser amounts, or not at all, according to achievement of performance goals.
(2)Price applies only to the Options and SARs included in column (a). Exercise price is not applicable to the other awards included in column (a).
(3)A plan provision requires each share covered by an award (other than Optionsstock appreciation rights (SARs) and SARs)Options) 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 the amount shown depending on the type of award granted. Additionally, under the plan, the amount shown 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.

SHARE REPURCHASE ACTIVITIES
Occidental’s share repurchase activities for the year ended December 31, 20132016, 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 2013  —
   $—
   —
     
Second Quarter 2013  239,444
(a) 
  $90.23
   —
     
Third Quarter 2013  410,000
   $87.28
   410,000
     
October 1-31, 2013  669,309
(a) 
  $95.29
   557,168
     
November 1-30, 2013  3,870,000
   $96.91
   3,870,000
     
December 1-31, 2013  5,452,239
   $93.10
   5,452,239
     
Fourth Quarter 2013  9,991,548
   $94.72
   9,879,407
     
Total 2013  10,640,992
   $94.34
   10,289,407
   
6,966,168 (b)
 
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 2016  103,371
(a) 
  $70.63
   —
     
Second Quarter 2016  96,449
(a) 
  $76.06
   —
     
Third Quarter 2016  96,151
(a) 
  $70.50
   —
     
October 1 - 31, 2016  —
   $—
   —
     
November 1 - 30, 2016  —
   $—
   —
     
December 1 - 31, 2016  —
   $—
   —
     
Fourth Quarter 2016  —
   $—
   —
     
Total 2016  295,971
(a) 
  $72.36
   —
   63,756,544
(b) 
(a)IncludesRepresents 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-endyear end under Occidental's share repurchase program of 95 million. In February 2014, Occidental increased the number of shares authorized for its185 million shares. The program by 30 million; however, thewas initially announced in 2005. The program does not obligate Occidental to acquire any specific number of shares and may be discontinued at any time.

9



PERFORMANCE GRAPH
The following graph compares the yearly percentage change in Occidental’s cumulative total return on its common stock with the cumulative total return of the Standard & Poor's 500 Stock Index (S&P 500), which Occidental is included in, and with that of Occidental’s current and prior peer groupsgroup over the five-year period ended on December 31, 20132016. The graph assumes that $100 was invested at the beginning of the five-year period shown in the graph below inin: (i) Occidental common stock, (ii) the stock of the companies in the S&P 500, and (iii) each of the current and prior peer group companies' common stock weighted by their relative market values within the respective peer groups,group, and that all dividends were reinvested.
In 2013, Occidental revised its peer group (which includes Occidental) to ensure the companies continue to provide appropriate comparability to Occidental. Prior to the revision, Occidental's peer group consisted of Anadarko Petroleum Corporation, Apache Corporation, Canadian Natural Resources Limited, Chevron Corporation, ConocoPhillips, Devon Energy Corporation, EOG Resources Inc., ExxonMobil Corporation, Hess Corporation, Royal Dutch Shell plc, Total S.A. and Occidental. Occidental's current peer group consists of Anadarko Petroleum Corporation, Apache Corporation, Canadian Natural Resources Limited, Chevron Corporation, ConocoPhillips, Devon Energy Corporation, EOG Resources Inc., ExxonMobil Corporation, Hess Corporation, Marathon Oil Corporation, Total S.A. and Occidental.


 12/31/2008 12/31/2009 12/31/2010 12/31/2011 12/31/2012 12/31/2013
$100 $138 $170 $165 $139 $177
                  
 100  109  124  136  138  166
                  
 100  107  121  132  135  164
                  
 100  126  146  149  172  228
 12/31/2011 12/31/2012 12/31/2013 12/31/2014 12/31/2015 12/31/2016
$100 $84 $107 $98 $85 $94
                  
 100  102  125  117  95  120
                  
 100  116  154  175  177  198

The information provided in this Performance Graph shall not be deemed "soliciting material" or "filed" with the Securities and Exchange CommissionSEC or subject to Regulation 14A or 14C under the Exchange Act, other than as provided in Item 201 to Regulation S-K under the Exchange Act, or subject to the liabilities of Section 18 of the Exchange Act and shall not be deemed incorporated by reference into any filing under the Securities Act of 1933 or the Exchange Act except to the extent Occidental specifically requests that it be treated as soliciting material or specifically incorporates it by reference.
_______________________
(1)The cumulative total return of the peer group companies' common stock includes the cumulative total return of Occidental's common stock.


10



ITEM 6SELECTED FINANCIAL DATA

FIVE-YEAR SUMMARY OF SELECTED FINANCIAL DATA
Dollar amounts (in millions, except per-share amountsamounts)
As of and for the years ended December 31, 2013 2012 2011 2010 2009 2016 2015 2014 2013 2012 
RESULTS OF OPERATIONS (a)
                     
Net sales $24,455
 $24,172
 $23,939
 $19,045
 $14,814
 $10,090
 $12,480
 $19,312
 $20,170
 $20,100
 
Income from continuing operations $5,922
 $4,635
 $6,640
 $4,569
 $3,151
Net income attributable to common stock $5,903
 $4,598
 $6,771
 $4,530
 $2,915
Basic earnings per common share from continuing operations $7.35
 $5.72
 $8.16
 $5.62
 $3.88
Basic earnings per common share $7.33
 $5.67
 $8.32
 $5.57
 $3.59
Diluted earnings per common share $7.32
 $5.67
 $8.32
 $5.56
 $3.58
Income (loss) from continuing operations $(1,002) $(8,146) $(130) $4,932
 $3,829
 
Net income (loss) attributable to common stock $(574) $(7,829) $616
 $5,903
 $4,598
 
Basic earnings (loss) per common share from continuing operations $(1.31) $(10.64) $(0.18) $6.12
 $4.72
 
Basic earnings (loss) per common share $(0.75) $(10.23) $0.79
 $7.33
 $5.67
 
Diluted earnings (loss) per common share $(0.75) $(10.23) $0.79
 $7.32
 $5.67
 
                     
FINANCIAL POSITION (a)
                     
Total assets $69,443
 $64,210
 $60,044
 $52,432
 $44,229
 $43,109
 $43,409
 $56,237
 $69,415
 $64,175
 
Long-term debt, net $6,939
 $7,023
 $5,871
 $5,111
 $2,557
 $9,819
 $6,855
 $6,816
 $6,911
 $6,988
 
Stockholders’ equity $43,372
 $40,048
 $37,620
 $32,484
 $29,159
 $21,497
 $24,350
 $34,959
 $43,372
 $40,048
 
                     
MARKET CAPITALIZATION (b)
 $75,699
 $61,710
 $75,992
 $79,735
 $66,050
 $54,437
 $51,632
 $62,119
 $75,699
 $61,710
 
                     
CASH FLOW          
CASH FLOW FROM CONTINUING OPERATIONS           
Operating:                     
Cash provided by operating activities $12,927
 $11,312
 $12,281
 $9,566
 $5,946
Cash flow from continuing operations $2,519
 $3,254
 $8,871
 $10,229
 $9,050
 
Investing:                     
Capital expenditures $(9,037) $(10,226) $(7,518) $(3,940) $(3,245) $(2,717) $(5,272) $(8,930) $(7,357) $(7,874) 
Cash provided (used) by all other investing activities, net $844
 $(2,429) $(2,385) $(5,355) $(2,221) $(2,025) $(151) $2,686
 $1,040
 $(1,989) 
Financing:                     
Cash dividends paid $(1,553)
(c) 
$(2,128)
(c) 
$(1,436) $(1,159) $(1,063) $(2,309) $(2,264) $(2,210) $(1,553)
(c) 
$(2,128)
(c) 
Cash (used) provided by all other financing activities, net $(1,380) $1,282
 $261
 $2,242
 $30
Purchases of treasury stock $(22) $(593) $(2,500) $(943) $(583) 
Cash provided (used) by all other financing activities, net $2,722
 $4,341
 $2,384
 $(437) $1,865
 
                     
DIVIDENDS PER COMMON SHARE $2.56
 $2.16
 $1.84
 $1.47
 $1.31
 $3.02
 $2.97
 $2.88
 $2.56
 $2.16
 
                     
WEIGHTED AVERAGE BASIC SHARES OUTSTANDING (thousands) 804,064
 809,345
 812,075
 812,472
 811,305
WEIGHTED AVERAGE BASIC SHARES OUTSTANDING (millions) 764
 766
 781
 804
 809
 
Note: Argentine operations were sold in February 2011The statements of income and cash flows related to California Resources have been reflectedtreated as discontinued operations for all applicable periods.periods 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 AND 7A
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (MD&A)
In this report, "Occidental" means Occidental Petroleum Corporation (OPC), or OPC and one or more entities in which it owns a controlling interest (subsidiaries). Occidental's principal businesses consist of three segments operated by OPC's subsidiaries and affiliates.segments. The oil and gas segment explores for, develops and produces oil and condensate, natural gas liquids (NGL)(NGLs) and natural gas. The chemical segment (OxyChem) mainly manufactures and markets basic chemicals and vinyls. The
 
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 other commodities.capacity. Additionally, the midstream and marketing segment invests in entities that conduct similar activities.


11



STRATEGY
General
Through its operations, Occidental aims to maximize total returns to stockholders using the following strategies:Total Shareholder Return through a combination of:
ØGrow 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;Consistent dividend growth;
ØAllocateValue growth through oil and deploy capital with a focus on achievinggas development that meets above cost-of-capital returns well in excess(ROE and ROCE) and return targets of Occidental's cost of capital;greater than 15 percent and 20 percent for domestic and international projects, respectively;
ØProvide consistent dividend growth;Target growth rates of 5 percent to 8 percent average per year over the long-term; and
ØMaintain financial discipline and a strong balance sheet.
In conducting its business, Occidental accepts commodity, engineering and limited exploration risks. Occidental seeks to limit its financial and political risks.
To maximize returns, Occidental from time to time reviews its business strategy. In October 2013 and February 2014, Occidental’s Board of Directors authorized several actions resulting from a strategic review to streamline and focus operations in order to better execute Occidental’s long-term strategy and enhance value for shareholders. The authorized actions included:
ØPursue the sale of a minority interest in the Middle East/North Africa operations in a financially efficient manner.
ØPursue strategic alternatives for select Midcontinent assets, including oil and gas interests in the Williston Basin, Hugoton Field, Piceance Basin and other Rocky Mountain assets.
ØPursue the sale of a portion of Occidental’s investment in the General Partner of Plains All-American Pipeline, L.P. (Plains Pipeline).
ØSeparation of its California assets into an independent and separately traded company.
With respect to these initiatives, since October, Occidental:
ØSold a portion of Plains Pipeline, while continuing to hold an approximate 25-percent interest;
ØMade steady progress on discussions with key partners in countries where Occidental operates in the Middle East/North Africa region for the sale of a minority interest in its operations there; and
ØEntered into an agreement to sell its Hugoton operations.
The strategic review underway is expected to result in significant changes to Occidental’s asset mix. Occidental's capital program, production expectations and other elements of its future plans will be adjusted as related transactions are concluded. Proceeds resulting from these actions will largely be used to reduce Occidental's capitalization. In the fourth quarter of 2013 Occidental bought back almost 10 million shares of its own stock for approximately $0.9 billion using the proceeds from the
Plains Pipeline sale. Occidental also retired $0.6 billion of its debt in the fourth quarter.
Occidental prioritizes the use of its operating cash flows in the following order:
ØBase/Maintenance capital
ØDividends
ØGrowth capital
ØShare repurchases
ØAcquisitions
Capital is employed to operate all assets in a safe and environmentally sound manner. Management aimsOccidental seeks to developlimit its financial and political risks.
Price volatility is inherent in the oil and gas business. In 2016, Occidental continued to experience a challenging price environment with low oil, natural gas and NGLs prices. In order to manage this risk, Occidental strives to retain sufficient cash on hand and may access capital markets, as necessary.
In connection with Occidental's assets in a manner that would contribute substantially to earnings and cash flow after invested capital. strategic review initiatives, Occidental:
Ø
Acquired producing and non-producing leasehold acreage, CO2 properties and related infrastructure in the Permian Basin, which leverages existing infrastructure and operational synergies; and
ØCompleted its exit of non-core operations in the Piceance Basin, Bahrain, Iraq, Libya and Yemen.

The following describes the application of Occidental'sOccidental’s overall strategy tofor each of its operating segments.segments:

Oil and Gas

Segment Earnings
($ millions)
Occidental prefers to hold large, long-lived "legacy" oil and gas assets, like those in California and the Permian Basin, that tend to have enhanced secondary and tertiary recovery opportunities and economies of scale that lead to cost-effective production. Occidental also focuses a growing portion of its drilling activities on unconventional shale opportunities.
The oil and gas business seeks to increase its oil and gas production profitably and add new reserves at a pace ahead of production while minimizing costs incurred for finding and development of such reserves. The oil and gas business implements this strategy within the limits of the overall corporateOccidental's strategy primarily by:
ØDeploying capital efficiently to fully developOperating and developing areas where reserves are known to exist and to increase production from maturecore areas, primarily in the Permian Basin, Colombia, Oman, Qatar and underdeveloped fields and from unconventional acreage by applying appropriate technology and advanced reservoir-management practices;UAE;


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ØAdding reserves through a combinationFocusing on cost-reduction efficiencies, improvement in new well productivity and better base management to reduce total spend per barrel;
Ø
Using enhanced oil recovery techniques, such as CO2, water and steam floods, in mature fields;
ØFocusing many of focused explorationOccidental's subsurface characterization and development programs conducted in Occidental's core areas,technical activities on unconventional opportunities, primarily in the United States but alsoPermian Basin. This focus is in the Middle East/North Africa and Latin America;support of a sizable capital program within these developments; and
ØMaintaining a disciplined and prudent approach with capital expenditures to acquisitionsfocus on returns and divestitures with an emphasis on transactions at attractive prices.maintain
Over the past several years, Occidental built a large portfolio of growth-oriented assets in the United States.
discipline, with an emphasis on creating value and further enhancing Occidental's existing positions.
In 2013, Occidental spent a much larger portion of its investment capital on the development of this portfolio. Acquisitions in 2013 were at a multi-year low of approximately $0.5 billion, all for domestic2016, oil and gas properties. Compared to recent years, this reduced acquisitioncapital expenditures were approximately $2.0 billion, and were mainly comprised of expenditures in the Permian Basin and the Middle East. This activity reflects Occidental's strategy to capitalizefocus on achieving returns above the opportunities presented by its existing portfoliocost of assets.capital even in a low price environment.
Management currently believes Occidental's oil and gas segment growth will come domestically from higher oil productionoccur primarily through exploitation and development opportunities in California and the Permian Basin and internationally from opportunitiesColombia and focused international projects in key assets, mainly in Oman and Qatar, as well as the completion of the Al Hosn gas project in late 2014.Middle East.

Chemical

Segment Earnings
($ millions)
The primary objective of the chemical business (OxyChem)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.external customers. In addition, chlorine, together with ethylene, is converted through a series of intermediate products into PVC.polyvinyl chloride (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, expectsthrough 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. The joint venture will provide OxyChem with an ongoing source of ethylene, significantly reducing OxyChem's reliance on third-party ethylene suppliers. The construction of the ethylene cracker remains on budget and on schedule and is expected to begin operating the New Johnsonville, Tennessee chlor-alkali facility in early 2014. During2017. In 2016, capital expenditures for OxyChem totaled $324 million. Additionally, $160 million was spent on the secondMexichem joint venture. In the first quarter of 2013, Occidental2016, OxyChem sold its investmentOccidental Tower building in Carbocloro, a Brazilian joint venture,Dallas for a pre-tax gain of $131approximately $57 million and a non-core specialty chemicals business for a pre-tax gain of approximately $31 million. In the fourth quarter2016, OxyChem announced a $145 million expansion of 2013,its manufacturing plant in Geismar, Louisiana. The project will produce an OxyChem patented new raw material used in making next-generation, climate-friendly refrigerants with a low global warming and Mexichem, S.A.B. de C.V. formed a 50/50 joint venture to construct and operate a 1.2-billion-pound per year capacity ethylene crackerozone depletion potential. Construction work has begun with startup expectedan anticipated completion date in 2017, and entered into related supply agreements.late 2017.




Midstream and Marketing

Segment Earnings
($ millions)
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. In commodities trading, Occidental seeks to generate gains using net-long positions. The segment invests in and operates pipeline systems, gas plants, co-generation facilities, pipeline systems and storage facilities. The segment also seeks to minimize the costs of gas, power and other commodities used in Occidental's businesses, and to limitwhile 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. OccidentalIn 2016, capital expenditures totaled $358 million related to Permian Basin gas processing and Magellan Midstream Partners, L.P. (Magellan) are proceeding with the construction of the BridgeTex Pipeline, which will transport crude oil between the Permian regiongathering infrastructure, Al Hosn Gas and the Gulf Coast refinery markets and is expected to begin service in mid-2014. In 2013, Occidental completed the sale of a portion of its investment in Plains Pipeline, resulting in a $1.0 billion pre-tax gain.Ingleside Crude Terminal.



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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:
ØCash margin per barrel;Health, environmental, safety and process metrics;
ØFree-cash-flow yield;
ØDividend growth;Total Shareholder Return, including funding the dividend;
ØReturn on equity (ROE) and return on capital employed (ROCE); and
ØFull cycleSpecific measures such as total spend per barrel, per-unit profit, production cost, cash margin.
Occidental also monitors other segment-specific indicators such as per-unit profit, production costs and finding and development costs, as well as health, environmental and safety measures such as the number of recordable injuries, and others.
Based on the $2.88 per share annual dividend rate announced in February 2014, Occidental’s dividend rate has increased by 476 percent since 2002. While its stockholders' equity increased by 8 percent for 2013 and 34 percent for the three-year period from 2011 through 2013, Occidental continued to deliver above-cost-of-capital returns as follows:
  
Annual 2013 (a)
 
Three-Year Annual
Average 2011 - 2013 (b)
ROE 14.2% 15.0%
 {13.3%} 
ROCE 12.2% 13.1%
 {11.5%} 
(a)
The top figures were calculated by dividing Occidental's 2013 net income (adding back after-tax interest expense for ROCE) by its average equity (using debt and equity for ROCE) during 2013. The bottom figures were calculated in the same manner as the top figures, except that they exclude the effects of Significant Items Affecting Earnings described on page 25. We provide this adjusted measure because we believe it would be useful to investors in evaluating and comparing Occidental's performance between periods, not as a substitute for the measure calculated using net income.
(b)The three-year averages were calculated by dividing Occidental's average net income (adding back after-tax interest expense for ROCE) over the three-year period by its average equity (using debt and equity for ROCE) over the same period.
  2013 2012
Full cycle cash margin (a)
 $34.16
 $21.28
(a)Amounts were calculated by subtracting operating costs, taxes other than on income and general and administrative expenses for producing operations, all on a per BOE basis, from realized price for the year. Subtracted from this amount is theflow, finding and development costs per BOE, calculated by dividing exploration and development costs incurred, including asset retirement obligations, but excluding acquisition costs, by proved reserve additions for the year from improved recovery, extensions, discoveries and revisions. Reserve additions include proved undeveloped reserves for which estimated future development costs are included in amounts disclosed in the Supplemental Oil and Gas Information - Standardized Measure of Discounted Future Net Cash Flows.replacement percentages.

Debt Structure
In 2013, Occidental decreased its debt balance by $690 million, which reduced its debt-to-capitalization (debt and equity) ratio from 16 percent at year-end 2012 to 14 percent at year-end 2013.

OIL AND GAS SEGMENT
Business Environment
Oil and gas prices are the major variables that drive the industry’s short- and intermediate-term financial performance. The following table presents the average daily West Texas Intermediate (WTI), Brent and New York Mercantile Exchange (NYMEX) prices for 20132016 and 2012:2015:
 2013 2012 2016 2015
WTI oil ($/barrel) $97.97
 $94.21
 $43.32
 $48.80
Brent oil ($/barrel) $108.76
 $111.70
 $45.04
 $53.64
NYMEX gas ($/Mcf) $3.66
 $2.81
 $2.42
 $2.75

The following table presents Occidental's average realized prices as a percentage of WTI, Brent and NYMEX for 20132016 and 2012:2015:
 2013 2012 2016 2015
Worldwide oil as a percentage of average WTI 102% 106% 89% 97%
Worldwide oil as a percentage of average Brent 92% 89% 86% 88%
Worldwide NGLs as a percentage of average WTI 42% 48% 34% 33%
Worldwide NGLs as a percentage of average Brent 33% 30%
Domestic natural gas as a percentage of NYMEX 92% 93% 79% 78%

Average WTI and Brent oil price indexes declined 11 percent and 16 percent, from $48.80 and $53.64 in 2015 to $43.32 and $45.04 in 2016, respectively. Average worldwide realized oil prices were flatfell $8.37, or 18 percent, in 20132016 compared to 2012. Approximately 60 percent2015. However, the WTI and Brent oil price indexes increased significantly in the fourth quarter of Occidental’s oil production tracks world oil prices, such2016, closing at $53.72 per barrel and $56.82 per barrel, respectively, as Brent, and 40 percent tracks WTI.of December 31, 2016, well above the 2016 average prices. The average realized domestic natural gas price in 2013 increased 292016 decreased 12 percent from 2012.2015. Average NYMEX natural gas prices declined 12 percent, from $2.75 in 2015 to $2.42 in 2016.
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.
The decline in oil and gas prices during 2016 and 2015, as well as the decision to sell or exit non-core assets, caused Occidental to assess the carrying value of all of its oil and gas producing assets and assess development plans for its non-producing assets. In 2016, impairment and related charges were immaterial. In 2015, Occidental recorded total pre-tax impairment and related charges of $3.5 billion for its domestic assets and $5.0 billion for its international assets. To assess carrying value of its oil and gas assets, Occidental uses oil and gas price curves settled on the last trading day of each quarter. While oil and gas future prices were increasing at the end of 2016 any future sustained declines in commodity prices may result in additional impairments in the future.

Operations
2016 Developments
In March 2016, Occidental completed the sale of its Piceance Basin operations in Colorado for approximately $153 million resulting in a pre-tax gain of $121 million.
In September 2016, Occidental completed the sale of its South Texas Eagle Ford non-operated properties for $63 million resulting in a pre-tax gain of $59 million.
In October 2016, Occidental acquired producing and non-producing leasehold acreage in the Permian Basin. This acquisition includes 35,000 net acres in Reeves and Pecos counties, Texas, in the Southern Delaware Basin, in areas where Occidental currently operates or has working interests. Separately, Occidental also acquired working interests in several producing oil and gas properties with CO2 floods and related EOR infrastructure, increasing Occidental's ownership in several properties where it is currently the operator or an existing working interest partner. The total purchase price for these



transactions was approximately $2.0 billion.
In 2016, Occidental completed its exit of non-core operations in Bahrain, Iraq, Libya and Yemen.

Business Review
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 8.23.6 million net acres in which Occidental has interests, approximately 7484 percent is leased, 2515 percent is owned subsurface mineral rights and 1 percent is owned land with mineral rights.

Production-Sharing Contracts (PSC)The following charts show Occidental’s domestic total production volumes for the last five years:

Domestic Production Volumes
(thousands BOE/day)
Notes:
Excludes volumes from California Resources, which was separated on November 30, 2014, and included as discontinued operations for all applicable periods.
Operations sold include Piceance (sold in March 2016), Williston (sold in November 2015) and Hugoton (sold in April 2014)

United States Assets
United States

1.Permian Basin
2.South Texas and Other interests

Permian Basin
Occidental's Permian Basin production is diversified across a large number of producing areas. The basin extends throughout west 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 12 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, which utilizes enhanced oil recovery techniques such as CO2 floods and waterfloods. During 2016, the Permian operations focused on full cycle value through capital efficiency, reduced operating expense, improved base production and new well productivity. In the Permian Basin, Occidental spent over $1.2 billion of capital in 2016, with 60 percent spent on Permian Resources assets. In 2017, Occidental expects to allocate approximately one third of the 2017 capital budget to Permian Resources for focused development areas in the Midland and Delaware Basins and approximately 10 to 15 percent to Permian EOR in order to add to existing facilities to increase CO2 production and injection capacity for future projects.
Occidental's Permian Resources operations are among its fastest growing assets with over 11,650 drilling locations in its horizontal inventory located in the Midland and Delaware sub-basins. This inventory was developed using data gathered from appraisal efforts, and development drilling, along with offset operators drilling activities. As of year end, approximately 650 of these drilling locations represented proved reserves. Continued wellbore placement and completion optimization through advanced subsurface characterization and the application of enhanced manufacturing principles, combined with projected commercial savings, are expected to increase the well inventory even further. The development program, which largely began in 2010, continued in 2016. In 2016, Permian Resources drilled 63 horizontal wells. Production from Permian Resources comes from approximately 5,550 net wells, of which 23 percent are operated by other operators. These investments in Permian wells operated by others allows Occidental to access and leverage additional data in the same areas where it is operating. By analyzing the operated by others data with the significant amount of data Occidental has gathered, its Permian operations are able to use the information to aid in reducing operating expenses, gain drilling and completions efficiencies, increase the productivity of its wells and improve the base production. In 2016, Permian Resources added 92 million BOE to Occidental's proved reserves.
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 31 active floods and over 40 years of experience, Permian EOR is the industry leader in Permian Basin CO2 flooding.
Occidental is an industry leader in applying this technology, which can increase ultimate oil recovery by 10 to 25 percent in the fields where it is employed. Significant opportunity remains to expand Occidental's existing projects into new portions of reservoirs that thus far have only been water-flooded, leaving opportunity for significant additional recovery with new CO2 injection. 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 125 wells deepened in 2016 and 100 wells planned for 2017. Occidental utilizes workover rigs to drill the extra depth into additional CO2 floodable sections of the reservoir. These are low cost projects that 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. In 2016, Permian EOR had its largest improved recovery additions in more than 10 years adding 72 million BOE to Occidental's proved reserves, primarily as a result of executing CO2 flood development projects and expansions as well as extending the approved CO2 slug size of current floods.
The current strategy for Permian EOR is to invest sufficient capital to maintain current production and provide cash flow. 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 269,000 BOE per day in 2016 with 124,000 BOE per day coming from Permian Resources and 145,000 BOE per day from Permian EOR.

South Texas and Other
Occidental hasholds approximately 178,000 net acres in South Texas. Occidental's share of production in South Texas and Other was approximately 33,000 BOE per day.

International Interests
Production-Sharing Contracts
Occidental's interests thatin Oman and Qatar are operated under PSCs or similarsubject to production sharing contracts in Bahrain, Iraq, Libya, Oman, Qatar and Yemen.(PSC). Under such contracts, Occidental records a share of production and reserves to recover certain production costs and an additional share for profit. In addition, Occidental's share of production and reserves from operations in Long Beach, California, and certain contracts in Colombia are subject to contractual


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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 showscharts show Occidental’s totalinternational production volumes for the last five years:

WorldwideInternational Production Volumes
(thousands BOE/day)

Notes:
Excludes volumes from the Argentine operationsOperations sold in 2011or exited include Bahrain, Iraq, Libya and classified as discontinued operations.Yemen.

United StatesMiddle East Assets
United StatesMiddle East

1.Permian Basin
2.California
3.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 15 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 15 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 EOR (enhanced oil recovery), which includes CO2 and waterfloods, and Permian Resources, which includes growth-oriented unconventional opportunities. During 2013, capital efficiency efforts reduced drilling costs per well by 25 percent for the Permian Basin operations while operating expenses decreased by $3.22 per barrel, or 17 percent. In addition, management began transitioning to a horizontal drilling program to take advantage of unconventional and shale opportunities. In the Permian Basin, Occidental spent over $1.7 billion of capital in 2013 with 64 percent spent on Permian Resources assets. In 2014, Permian Basin capital spending is expected to be slightly less than $2.2 billion. The entire $450 million increase will be spent on Permian Resources assets and will focus on growing oil production. Approximately 70 percent of the total capital to be spent in the Permian Basin will be for Permian Resources assets.
Occidental's Permian Resourcesoperations are among its fastest-growing assets and held approximately 1.9 million net acres at the end of 2013, including acreage with prospective resource potential. The development program, largely begun in 2010, continued to increase in 2013, accounting for more than 285 wells drilled. In 2013, Permian Resources drilled 49 horizontal wells and expects this to increase in 2014 to approximately 172 of its 345 total planned wells. Production from this business unit comes from approximately 9,500 gross wells, of which 54 percent are operated by other producers. On a net basis, this represents approximately 4,400 wells, of which only 15 percent are operated by others.
The Permian EOR business unit operates a combination of CO2 and waterfloods which have similar development characteristics and ongoing monitoring and maintenance requirements. Approximately 74 percent of Occidental’s Permian EOR oil production is from fields that actively employ CO2 flood technology, an enhanced oil recovery technique. These CO2 flood operations make Occidental a world leader in the application of this technology. Occidental believes it has the ability to accelerate growth in the Permian EOR projects as more CO2 becomes available. Over the past several years, Occidental has focused more capital on waterfloods than CO2 developments. Of the $660 million in capital spending Permian EOR plans for 2014, 25 percent will be used for current waterflood development and the remainder for CO2 floods.
Occidental's share of production in the Permian Basin was approximately 212,000 BOE per day in 2013.

California
Occidental's California operations include interests in the San Joaquin Valley, the Wilmington and other fields in the Los Angeles Basin, and the Ventura and Sacramento Basins. Occidental is California's largest producer of natural gas and the largest oil and gas producer on a gross-


15


operated-BOE basis and has properties in approximately 130 fields. Occidental manages its California operations through separate teams focused on waterfloods; steam floods for heavy oil resources; and unconventional and other developing plays.
The main California objectives in 2013 were to deliver a predictable outcome, advance low-risk projects that contribute to long-term growth, reduce the cost structure, lower the base decline, create a more balanced portfolio and test exploration and development concepts. Occidental believes it achieved all of these objectives in 2013, notably progressing the development of its multi-year steam floods in Kern Front and Lost Hills, bringing its Huntington Beach Field waterflood redevelopment online, further developing its Wilmington Field, improving capital efficiency by 20 percent and reducing operating costs by $4.70 per BOE, or 20 percent.
Occidental increased the 2013 oil development capital spending to almost 90 percent of the total capital for California. Of the $1.5 billion of capital spent in 2013, 39 percent was for waterfloods, 22 percent for steam floods and 39 percent for unconventional and other developing plays. The 2014 program will continue efforts in each of these areas with increased efforts in horizontal wells in Occidental's waterfloods, new pilot projects in its steam floods and increased unconventional drilling. The allocation for the $1.9 billion 2014 capital program is expected to be similar to 2013. The 2014 capital strategy is to continue focusing the majority of capital spending on projects identified as low-decline, low-risk, and high-return that are expected to provide long-term growth and capitalize on recent exploration successes. Occidental drilled approximately 770 wells in California during 2013 and plans to drill approximately 1,050 wells in 2014, including 175 waterflood wells in the LA Basin, 420 wells for steam floods and 130 unconventional shale wells at Elk Hills.
Over the next several years, there will be some rebalancing between high-decline, such as Elk Hills, and low-decline assets. With the higher investments in water and steam floods, production from these fields is expected to grow faster. The investments being made in high-decline assets are expected to moderate their decline. As a result, the balance of assets in the California portfolio is expected to shift towards low-decline assets over time.
In addition, Occidental holds more than 2.3 million net acres in California, the large majority of which are net fee mineral interests. As a result, Occidental has a substantial inventory of properties available for future development and exploitation opportunities. Currently, approximately one-third of California production is from unconventional reservoirs and Occidental holds more than 1.1 million net acres for such resources.Occidental's share of production in California was approximately 154,000 BOE per day in 2013.
Midcontinent and Other
The Midcontinent and Other properties include interests in the Hugoton Field, the Piceance Basin, the Williston Basin, and the Eagle Ford Shale and other areas in South Texas. These properties are located in Kansas,
Oklahoma, Colorado, North Dakota and Texas. Occidental holds over 2.3 million net acres in the Midcontinent region, which includes 1.4 million net acres in a large concentration of gas reserves and production and royalty interests in the Hugoton area and approximately 168,000 net acres in the Piceance area. Occidental also holds approximately 176,000 net acres in South Texas, including 4,000 net acres in the Eagle Ford Shale. In addition, Occidental holds approximately 335,000 net acres of oil-producing and unconventional properties in the Williston Basin's Bakken, Three Forks and Pronghorn formations.
In Midcontinent and Other, Occidental drilled approximately 175 wells and produced approximately 108,000 BOE per day in 2013.

Other Developments
During its annual capital planning process in the fourth quarter of 2013, 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 $0.6 billion for the acreage.

Middle East/North Africa Assets
 
Middle East/North Africa
1.Bahrain
2.Iraq
3.Libya
4.Oman
5.Qatar
6.2.United Arab Emirates
7.3.YemenOman

Bahrain
In 2009, Occidental and other consortium members began operating the Bahrain Field under a 20-year development and production sharing agreement (DPSA). Occidental has a 48-percent working interest in the joint venture. Since handover of operations, the consortium has increased gross gas production capacity more than 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 44,000 barrels per day. Occidental's share of production from Bahrain during 2013 was approximately 241 million cubic feet (MMcf) per day of gas and 3,000 barrels of oil per day.



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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. Past delays in 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 17,000 BOE per day in 2013.

Libya
Occidental participates with the Libyan National Oil Company in the Sirte Basin producing operations. These agreements continue through 2032. In 2013, production was disrupted for a significant portion of the year due to field and port strikes. Occidental does not know when operations will return to normal levels. The 2013 production volume was approximately 7,000 BOE per day.

Oman
In Oman, Occidental is the operator of Block 9 andwith a 50-percent working interest, 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-percentan 80-percent working interest.
In December 2015, the existing production sharing contract for Block 9 expired and Occidental agreed to operate Block 9 under modified operating terms until a new contract is approved. The Block 9 Exploration and Production Sharing Agreement 15-year extension was signed in January 2017 and will be effective upon ratification through Royal Decree. In 2016, the average gross production from Block 9 was 94,000 BOE per day. 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 2013,2016, Occidental had drilled more than 2,1002,900 new wells and continued implementation of a major steamflood project. In 2013,2016, the average gross daily production was 123,000127,000 BOE per day, including a record fourth quarter production of 133,000 BOE per day, which was over 15approximately 16 times higher than the production rate in September 2005 when Occidental assumed operations.
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.
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 natural 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. Production commenced in January 2016.
In 2016, Occidental achieved record production in Oman, and Occidental's share of production from Oman was approximately 74,000averaged 96,000 BOE per day in 2013.2016.

Qatar
In Qatar, Occidental is the operator atof the offshore fields 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 12ISSD expire in 2019 and 2022, respectively. The term for Block 12 expires on May 31, 2017 and 2017, respectively.
this contract will not be extended. Production from Block 12 was not significant.
In 2013, Occidental received approvalhas continued to successfully implement large scale water flooding projects combined with state of the art horizontal drilling, advanced completion techniques as well as utilizing extensive automated artificial lift systems that are significantly extending the life of the field. Since the commencement of its operations in 1994, Occidental has boosted the production from the Government of Qatar for the fifth phase of field development of the ISND Field, intended to improve the ultimate recovery in all existing contract reservoirsIdd El Shargi fields by drilling over 200 additional production, water injection and water source wells and installing associated facilities required to support the additional wells. Occidental's aggregate investment is expected to exceed $3 billion through 2019400 percent with the goal of sustainingcurrent gross oil productionrates of around 95,000 BOE per day. The ISSD field recently demonstrated encouraging results and is achieving record levels at approximately 100,000 barrels per day during that period.of production. Despite complex marine operations, Occidental is recognized as the lowest cost in country oil operator.
Occidental'sOccidental also holds the Dolphin investment comprisesthat is comprised of two separate economic interests through which Occidental owns: (i) a 24.5-percent undivided interest in the upstream operations under a DPSADevelopment and Production Sharing Agreement with the Government of Qatar to develop and produce natural gas, NGLs and NGLscondensate 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 105,000108,000 BOE per day in 2013.2016.

United Arab Emirates
In 2011, Occidental acquired a 40-percent participating interest in the Al Hosn gas project,Gas, joining with the Abu Dhabi National Oil Company (ADNOC) in a 30-year joint venture agreement. Once fully operational, the project is anticipated to produceIn 2016, Al Hosn Gas gross production
exceeded expectations, producing over 500570 MMcf per day of natural gas of which Occidental’s net share would be over 200 MMcf per day. In addition, the project is expected to produce over 50,000and 95,000 barrels per day of NGLs and condensate in its highest month of whichproduction. Occidental’s net share would be over 20,000of production from Al Hosn Gas was 190 MMcf per day of natural gas and 32,000 barrels per day. Occidental’s day of NGLs and condensate in 2016.
Additionally, Al Hosn Gas includes gas processing facilities which are discussed further in "Midstream and Marketing Segment - Gas Processing Plants and CO20132 capital expenditures for this project were approximately $950 million. A substantial portion of the total expenditures to date has been incurred in connection with plantsFields and facilities and is included in the midstream and marketing segment. Occidental believes that its share of total 2014 capital for the project will be approximately $760 million. Initial production from this project is expected to commence in the fourth quarter of 2014.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 AfricaEast oil and gas operations.

Yemen
In Yemen, Occidental owns interests in: Block 10 East Shabwa Field, which extends through 2015 with a 40.4-percent interest that includes an 11.8-percent interest held in an unconsolidated entity, and Block S-1 An Nagyah Field, which is an Occidental-operated block with a 75-percent working interest that extends into 2023.
Occidental's share of production from the Yemen properties was approximately 12,000 BOE per day in 2013.



17


Latin America Assets
 
Latin America


1. Bolivia
2. Colombia

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

Colombia
Occidental has a working interestinterests in the La Cira-Infantas areaand Teca areas and has operations within the Llanos Norte Basin. Occidental's interests range from 39 to 61 percent and certain interests expire between 2023 and 2030,2038, while others extend through the economic limit of the areas. In 2016, Occidental started a thermal recovery pilot at the Teca heavy oil field and the initial results are better than anticipated. Production began from these pilots in 2016. Occidental's share of production from Colombia was approximately 29,00033,000 BOE per day in 2013.2016.
Occidental also holds working interests in the Tarija, Chuquisaca and Santa Cruz regions of Bolivia, which produce gas. Occidental's share of production from Bolivia was 1,000 BOE per day in 2016.

Proved Reserves
Proved oil, NGLNGLs 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, NGLNGLs and natural 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 20132016, 20122015and20112014 disclosures, the calculated average West Texas Intermediate oil prices



were $96.94, $94.71$42.75, $50.28 and $96.19$94.99 per barrel, respectively. The calculated average Brent oil prices for 2016, 2015and2014 disclosures were $44.49, $55.57 and $99.51, per barrel, respectively. The calculated average Henry Hub gas prices for 20132016, 20122015and2014 were $2.55, $2.66 and 2011 disclosures were $3.65, $2.79 and $4.04$4.42 per MMBtu, respectively.
Occidental had proved reserves at year-end 20132016 of 3,4832,406 million BOE, compared to the year-end 20122015 amount of 3,2962,200 million BOE. Proved reserves at year-end 20132016 and 20122015 consisted of, respectively, 6256 percent and 59 percent oil, each year, 1217 percent and 1015 percent NGLs and 2627 percent and 2826 percent natural gas. Proved developed reserves represented approximately 7077 percent and 7379 percent, respectively, of Occidental’s total proved reserves at year-end 20132016 and 2012. A substantial portion of the proved undeveloped (PUD) reserves as of December 31, 2013, as well as the increase in the share of PUDs in 2013, compared to 2012, was the result of PUDs from the Al Hosn gas project reserves, which represented 27 percent of total year-end
PUDs. Occidental expects to transfer a substantial portion of these reserves to the proved developed category at the end of 2014 when additional wells are drilled and initial production begins in the fourth quarter.2015.
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."

Changes in Proved Reserve AdditionsReserves
Occidental's total proved reserve additions from all sources were 470reserves increased 206 million BOE in 2013.  Over 90 percent2016, which included additions of these reserve additions were the result of187 million BOE from Occidental's development program.
 The total additionsChanges in reserves were as follows:
In(in millions of BOEBOE) 
Improved recovery348
Extensions and discoveries81
Purchases372016
Revisions of previous estimates 4159
Total additionsImproved recovery 470185
Extensions and discoveries2
Purchases137
Sales(46)
Production(231)
Total206

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 willmay negatively or positively affect whether these historical sourcesOccidental's reserves.

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, lower prices may decrease the economically recoverable reserves, particularly for domestic properties, because the reduced margin limits the expected life of the operations. Offsetting this effect, lower prices increase Occidental's share of proved reserve additions continue at similar levels.reserves under PSCs because more oil is required to recover costs. Conversely, when prices rise, Occidental's 2013 development program provided approximately 291share of proved reserves decreases for PSCs and economically recoverable reserves may increase for other operations. In 2016, positive revisions of 159 million BOE were primarily due to technical revisions in Al Hosn Gas and price
revisions in Oman due to the PSC impact, partially offset by negative domestic price revisions.
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 reserve additions domestically.technical data.

Improved Recovery
In 2013,2016, Occidental added proved reserves of 348185 million BOE from improved recovery through its EOR and infill drilling activities. Generally, the improved recovery additions in 2013 weremainly associated with the continued development of properties in Permian Basin California, Williston Basin, Qatar and Oman.Oman operations. 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


18


wells that allow recovery of reserves that would not be recoverable from existing wells.

Extensions and Discoveries
Occidental also added proved reserves from extensions and discoveries, which are dependent on successful exploration and exploitation programs. In 2013,2016, extensions and discoveries added 812 million BOE substantially all of which is attributablerelated primarily to the recognition of proved undevelopeddeveloped reserves from the Al Hosn gas project.in Oman.

Purchases of Proved Reserves
Occidental continues to seek opportunities 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 2013,2016, Occidental added 37purchased 137 million BOE through purchases of proved reserves largely consisting of several domestic acquisitions in the Permian Basin.Basin, which mainly came from acquisitions made in October 2016.

RevisionsSales of Previous EstimatesProved Reserves
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 affect2016, Occidental sold 46 million BOE in 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 requiredmainly related to recover costs. Conversely, when prices drop, Occidental's share of proved reserves increases for PSCsLibya and economically recoverable reserves may drop for other operations. In 2013, revisions of previous estimates provided an increase of 4 million BOE to proved reserves.
Reserve estimation rules require that estimated ultimate recoveries be much more likely to increase or remain constant than to decrease as changes are made due to increased availability of technical data. As a result, apart from the effect of product prices, it is generally more likely that future proved reserve revisions will be positive in aggregate over time rather than negative.Piceance.

Proved Undeveloped Reserves
In 2013,2016, Occidental had proved undeveloped reserve additions of 363195 million BOE mainly from Permian Basin improved recovery extensions and discoveries and purchases. Of the total additions, 270 million BOE represented additions from improved recovery, primarily in Permian Basin, California, Williston Basin and internationally in Qatar and Oman. Occidental added 15 million BOE through purchases of proved undeveloped reserves domestically in the Permian Basin. Additionally, the proved undeveloped reserves increased due to extensions and discoveries mainly from the Al Hosn gas project. These proved undeveloped reserve additions were partially offset by transfers of 15066 million BOE to the proved developed category as a result of the 20132016 development programs. Occidental incurredprograms



approximately $2.7 billion in 2013 to convert proved undeveloped reserves to proved developed reserves.
and 47 million BOE of negative price and price related revisions. Permian Basin California,and Oman Williston Basin and South Texas accounted for approximately 8889 percent of the reserve transfers from proved undeveloped to proved developed in 2013. While costs2016. Occidental incurred approximately $0.5 billion in 2016 to developconvert proved undeveloped reserves have generally increased over time, in 2013 domestic development costs per barrel decreased by 25 percent as a result of the capital efficiency initiatives.to proved developed reserves. A substantial portion of the PUDsproved undeveloped reserves as of December 31, 2013, as well as the increase in the share of PUDs in 2013, compared to 2012,2016, was the result of PUDs from the Al Hosn gas project reserves,development program in the Permian Basin, which represented 27represents 75 percent of total year-end proved undeveloped reserves. Occidental expects to transfer a substantial portion of these reserves to the proved developed category at the end of 2014 when additional wells are drilled and initial production begins in the fourth quarter.

Reserves Evaluation and Review Process
Occidental’sOccidental's estimates of proved reserves and associated future net cash flows as of December 31, 2013,2016, 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,


19


including the internal audit and review of Occidental's oil and gas reserves data. The Senior Vice President has over 30 years of experience in the upstream sector of the exploration and production business, and has held various assignments in North America, Asia and Europe. He is a three-time past Chair of the Society of Petroleum Engineers Oil and Gas Reserves Committee. He is an American Association of Petroleum Geologists (AAPG) Certified
Petroleum Geologist and currently serves on the AAPG Committee on Resource Evaluation. He is a member of the Society of Petroleum Evaluation Engineers, the Colorado School of Mines Potential Gas Committee and the UNECE Expert Group on Resource Classification. He is also an active member of the Joint Committee on Reserves Evaluator Training (JCORET). The Senior Vice President has Bachelor of Science and Master of Science degrees in geology from Emory University in Atlanta.
Occidental has a Corporate Reserves Review Committee (Reserves Committee), consisting of senior corporate officers, to review and approve Occidental's oil and gas reserves. The Reserves Committee reports to the Audit Committee of Occidental's Board of Directors during the year. Since 2003, Occidental has retained Ryder Scott Company, L.P. (Ryder Scott), independent petroleum engineering consultants, to review its annual oil and gas reserve estimation processes.
In 2013,2016, 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, 2013,2016, 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 20132016 year-end total proved reserves portfolio. In 2013,2016, Ryder Scott reviewed approximately 2118 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 7180 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 numerous current and anticipatedvarious market conditions. TheAverage annual WTI and Brent oil price indexes fluctuated throughout 2013, settlingfor 2016 were below the 2015 averages, but ended the year higher, closing at $98.42$53.72 per barrel and $110.80$56.82 per barrel, respectively, as of December 31, 2013.2016. Commodity prices remained relatively constant in early 2017.
Oil prices will continue to be affected byby: (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.
NGLNGLs 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, NGLNGLs 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 ofAlthough United States economic growth resulted in higher2016 lagged behind that of 2015, demand for domestically produced energy and feedstocks remained fairly constant as natural gas and ethylene pricing was lower on average than in 2015. Historically high planned and unplanned ethylene outages, resulting in higher raw material prices, though this did not haveprice volatility within the same effectspot market, and rising energy costs in the last half of 2016 put pressure on all product prices. Chemical segment earnings, excluding the gain on salechemical margins. The impact of the Carbocloro investment, decreased in 2013, primarily due to higher energy and ethylenefeedstock costs was partially offset by the end of 2016 as tighter supply in the caustic soda and lower chlor-alkali and chlorinated organics pricing driven by continued unfavorable supply and demand fundamentals.PVC markets resulted in improved margins.

Business Review
Basic Chemicals
During 2013, the modest pace ofIn 2016, the United States economic growth much ofrate was expected to be below the year resulted2.6 percent experienced in lackluster2015. The lower than expected U.S. growth rate tempered domestic demand and pricing for basic chemical products. Industryas the 2016 industry chlorine operating rates remained relatively flat with 2012 at approximatelyrate increased by only 1 percent, to 84 percent, preventingresulting in only a moderate improvement in chlorine price improvement, and prices ended approximately 4 percent below where they began.pricing. Exports of downstream chlorine derivatives into the vinyls chain remained competitivewere relatively strong in 2016 as a result of the North American feedstock cost advantages, which are driven mostly by natural gas prices.United States ethylene and energy costs were advantaged over global pricing. Liquid caustic soda prices fell overimproved both domestically and globally in the last two


20


three quarters of 2013 and were slightly below2016 as new capacity growth in the prior year levels for the whole year. In the domestic market, anticipation of additional capacity coming online in early 2014 from the commissioning of three additional chlor-alkali plants, including OxyChem’s 182,500-ton-per-year membrane plant in Tennessee, created downward pressure on liquid caustic soda prices during the second half of 2013. Export demand and pricing for liquid caustic soda was negatively impacted in mid-2013 by operational issues at a large Latin American alumina producer. Businesses such as calcium chloride and potassium hydroxide improved compared to 2012 as domestic demand improved and margins remained stable throughout the year.United States slowed.

Vinyls
Year-over-yearDemand for domestic and export PVC improved year- over-year 4.1 percent and 4.2 percent, respectively. Domestic demand grewwas driven by more than 4construction as housing starts continued their year-over-year increase and rising home values drove increased home remodeling. Export volume remains a significant portion of PVC sales representing over 30 percent on the strength of the housing and commercial construction markets. This was offset by a decrease in exports, resulting in no change intotal North American
producer’s production. PVC industry operating rates in 20132016 were approximately 2.3 percent higher than 2015. Industry PVC margins declined slightly in 2016 compared to 2012. Industry margins increased in 2013 due to higher2015, as PVC selling prices, partially offset by higherpricing decreased with lower ethylene costs. North American, ethane-based ethylene continues to be cost-competitive versus prices in Europe and Asia, giving North American vinyl products an advantage in global markets. Despite the year-over-year reduction in North American exports of PVC, export volumes represented nearly 35 percent of total PVC sales of North American producers.pricing.

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 by industry participants. Further strengthening of the U.S. dollar may cause headwinds in the U.S. commodity export market.

Basic Chemicals
Occidental expects that ifContinued improvement in the United States housing, automotive and durable goods markets continue to improve,should drive a moderate increase in domestic demand for basic chemical products should be higher in 2014. However, with forecasted capacity additions significantly exceeding closures, industry2017. Export demand for caustic is also expected to remain firm in 2017. Overall, the low chlor-alkali operating rates driven by capacity increases over the last few years should improve as the pace of expansions have slowed considerably both domestically and globally. Improved 2016 margins from historically low values in 2015 are expected to decline in 2014, resulting in increased competitive activity. Overall, improved demand in the face of increased capacity is anticipated to provide similar margins in 2014 for chlorine and caustic soda compared to 2013 levels. The continued competitiveness of downstream chlorine derivatives in global markets is contingent oncontinue as long as United States feedstock costs, primarily natural gas and ethylene, remainingremain favorable compared to other global markets.feedstock costs. Businesses such as calcium chloride and muriatic acid continue to be challenged but are expected to improve as oil prices rise.

Vinyls
North American demand andshould improve slightly in 2017 over 2016 levels as growth in construction spending continues with further upside potential driven by new infrastructure projects. North American operating rates are expected to remain relatively flat with 2016 but margins should improve as demand in 2014 if growth in both housing starts and commercial construction continues. Occidental expects export demand to remain firm and margins to improve over 2013.the United States strengthens.

MIDSTREAM AND MARKETING SEGMENT
Business Environment
Midstream and marketing segment earnings are affected by the performance of its marketing and trading businessesbusiness and its processing, transportation and power generation assets. The marketing business aggregates and trading businesses aggregate and marketmarkets Occidental's and third-party volumes trade commodities and engageengages 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 2013, excluding2016 were significantly higher than those in 2015, primarily due to impairments taken in 2015. Excluding the gain from the sale2015 impairments, 2016 earnings were lower because of a portion of an investment in Plains Pipeline, were greater than 2012, reflecting higher earnings in the pipeline



unfavorable contract pricing on long-term supply agreements as well as unfavorable Permian to Gulf Coast differentials, decreased throughput and power generation businesses and improved marketing and trading performance. These improvements were partially offset by lower income in the gas processing business due in part to plant turnarounds in the Permian Basin operations.realized NGLs pricing.

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 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. In addition, Occidental’s Phibro trading unit's strategy is to profit from market price changes. Marketing performance improved mainly as a result of capturing regional crude price differentials by utilizing new pipelines providing access to the Gulf Coast refineries.

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 2013 earnings from these operations decreased compared to 2012, which reflected lower NGL prices and plant turnarounds in the Permian Basin operations.
Occidental, together with ADNOC, is constructing a gas plant and facilities as part of the Al Hosn gas project in Abu Dhabi. The gas plant and facilities are expected to be completed and become operational in late 2014.



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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 2.32.2 Bcf per day.day, and up to 2.5 Bcf per day in the summer. 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 2,8002,900 miles of pipelines from southeast New Mexico across the Permian Basin of southwestin west Texas to Cushing, Oklahoma. The system has a current throughput capacity of about 616,000720,000 barrels per day, 5.87.1 million barrels of active storage capability and 95128 truck unloading facilities at various points along the system, which allow for additional volumes to be delivered into the pipeline.
Following the fourth quarter 2013 sale of a portion of its investment, Occidental owns approximately 25 percent of Plains Pipeline, a publicly-traded oil and gasOccidental's 2016 pipeline transportation storage, terminallingearnings declined from 2015 due to lower throughput volumes.

Gas Processing Plants and marketing entity operating in CanadaCO2 Fields and the westernFacilities
Occidental processes its and southern United States. The Plains Pipeline investment contributed over 25 percent of the segment's earnings for 2013, excluding the gainthird-party domestic wet gas to extract NGLs and other gas byproducts, including CO2, and delivers dry gas to pipelines. Margins primarily result from the sale.difference between inlet costs of wet gas and market prices for NGLs. Occidental’s 2016 earnings from these operations decreased compared to 2015 due to lower realized NGL pricing.
Occidental, and Magellan are proceedingtogether with constructionADNOC, developed Al Hosn Gas in Abu Dhabi, of the BridgeTex Pipeline, which Occidental has a 40-percent participating interest. Al Hosn Gas is expecteddesigned to begin service in mid-2014. The approximately 450-mile-long pipeline will be capable of transporting approximately 300,000 barrelsprocess 1.0 Bcf per day of crude oil betweennatural gas and separate it into sales gas, condensate, NGLs and sulfur. The processing facilities include processing and treatment facilities, sulfur recovery units, including facilities to extract sulfur from natural gas and to load and store sulfur. The facilities produce approximately 10,000 tons per day of sulfur, of which approximately 4,000 tons is Occidental's share. Al Hosn Gas facilities generates revenues from gas processing fees and the Permian region (Colorado City, Texas) and Gulf Coast refinery markets.sale of sulfur. The BridgeTex Pipeline project also includes construction of approximately 2.6 million barrels of oil storagedecrease in aggregate.
Occidental's 2013 pipeline transportation2016 earnings improvedcompared to 2015 was primarily due to higher volumes and pricing, and higher income from Plains Pipeline and the Dolphin Pipeline.lower sulfur pricing.

Power Generation Facilities
Earnings from power and steam generation facilities are derived from sales to affiliates and third parties and are generally not material.  parties. The
 
increase in earnings in 2016 compared to 2015 was a result of higher production due to fewer outages.

Marketing
The marketing group markets substantially all of Occidental’s oil, NGLs and gas production, as well as trades around its assets, including its own and third party transportation and storage capacity. Occidental’s third-party marketing 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 2016 declined compared to 2015 due to unfavorable Permian to Gulf Coast crude oil price differentials.

Industry Outlook
The pipeline transportation and power generation businesses are expected to remain relatively stable. Marketing results can have significant volatile results depending on significant price swings, as well as Permian to Gulf Coast crude oil differentials. Occidental continues to actively focus on marketing its commodity production to generate maximum value for its stakeholders. The gas processing plant operations could have volatile results depending mostly on NGLNGLs prices, which cannot reasonably be predicted. Generally, higher NGLNGLs prices result in higher profitability. Although the marketing and the trading businesses individually can be volatile, the operations together tend to offset each other, significantly reducing the overall volatility of the midstream and marketing segment. Based on its framework of controls and risk management systems, Occidental does not expect the volatility of these operations to be significant to the company as a whole.


SEGMENT RESULTS OF OPERATIONS AND SIGNIFICANT ITEMS AFFECTING EARNINGS
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 the year ended December 31, 2014. The assets and liabilities of California Resources were removed from Occidental's consolidated balance sheet as of November 30, 2014 because of the spin-off from Occidental.


22



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, 2013 2012 2011
NET SALES (a)
      
Oil and Gas $19,132
 $18,906
 $18,419
Chemical 4,673
 4,580
 4,815
Midstream and Marketing 1,538
 1,399
 1,447
Eliminations (a)
 (888) (713) (742)
  $24,455
 $24,172
 $23,939
EARNINGS      
Oil and Gas (b)
 $7,894
 $7,095
 $10,241
Chemical (c)
 743
 720
 861
Midstream and Marketing (d)
 1,573
 439
 448
  10,210
 8,254
 11,550
Unallocated corporate items      
Interest expense, net (e)
 (110) (117) (284)
Income taxes (3,755) (3,118) (4,201)
Other (f)
 (423) (384) (425)
Income from continuing operations 5,922
 4,635
 6,640
Discontinued operations, net (g)
 (19) (37) 131
Net Income $5,903
 $4,598
 $6,771
Basic Earnings per Common Share $7.33
 $5.67
 $8.32
(in millions, except per share amounts)
For the years ended December 31, 2016 2015 2014
NET SALES (a)
      
Oil and Gas $6,377
 $8,304
 $13,887
Chemical 3,756
 3,945
 4,817
Midstream and Marketing 684
 891
 1,373
Eliminations (a)
 (727) (660) (765)
  $10,090
 $12,480
 $19,312
SEGMENT RESULTS AND EARNINGS      
Domestic $(1,552) $(4,151) $(2,381)
Foreign 965
 (3,747) 2,935
Exploration (49) (162) (126)
Oil and Gas (b,c,d)
 (636) (8,060) 428
Chemical (e)
 571
 542
 420
Midstream and Marketing (f,g)
 (381) (1,194) 2,564
  (446) (8,712) 3,412
Unallocated corporate items      
Interest expense, net (275) (141) (71)
Income taxes 662
 1,330
 (1,685)
Other (h)
 (943) (623) (1,800)
Income (loss) from continuing operations (i)
 (1,002) (8,146) (144)
Discontinued operations, net (j)
 428
 317
 760
Net Income attributable to common stock $(574) $(7,829) $616
Basic Earnings per Common Share $(0.75) $(10.23) $0.79
See footnotes following significant transactions and events affecting Occidental's earnings.

The following table sets forth significant transactions and events affecting Occidental’s earnings that vary widely and unpredictably in nature, timing and amount.
Benefit (Charge) (in millions) 2016 2015 2014
OIL AND GAS      
Asset sales gains (b)
 $107
 $10
 $531
Asset impairments and related items domestic (c)
 (1) (3,457) (4,766)
Asset impairments and related items international (d)
 (70) (5,050) (1,066)
Total Oil and Gas $36
 $(8,497) $(5,301)
CHEMICAL      
Asset sales gains (e)
 $88
 $98
 $—
Asset impairments and related items —
 (121) (149)
Total Chemical $88
 $(23) $(149)
MIDSTREAM AND MARKETING      
Asset sale gains (f)
 $—
 $—
 $1,984
Asset impairments and related items (g)
 (160) (1,259) 31
Total Midstream and Marketing $(160) $(1,259) $2,015
CORPORATE      
Asset sale losses $—
 $(8) $—
Asset impairments (h)
 (619) (235) (1,358)
Severance, spin-off and other —
 (118) (61)
Tax effect of pre-tax and other adjustments 424
 1,903
 927
Discontinued operations, net of tax (j)
 428
 317
 760
Total Corporate $233
 $1,859
 $268
TOTAL $197
 $(7,920) $(3,167)

(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 2013 amount includes $607 million2016 gain on sale 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. The 2011 amount includes pre-tax charges of $35 million related to exploration write-offs in Libya and $29 million related to a Colombian net worth tax, and a pre-tax gain fromincluded the sale of an interest in a Colombian pipelinePiceance and South Texas oil and gas properties. The 2014 amount represented the gain on sale of $22 million.the Hugoton properties.
(c)The 20132015 amount includes a $131 million pre-tax gain fromincluded approximately $1.6 billion of impairment and related charges associated with non-core domestic oil and gas assets in the saleWilliston Basin (sold in November 2015) and Piceance Basin sold in March 2016. The remaining 2015 charges were mainly associated with the decline in commodity prices and management changes to future development plans. The 2014 amount was mainly comprised of an investment in Carbocloro, a Brazilian chemical facility.impairment and related charges on the Williston and Piceance assets.
(d)The 20132016 amount includesincluded a $1,030net charge of $61 million pre-tax gain fromrelated to the sale of a portionLibya and exit from Iraq. The 2015 amount included impairment and related charges of an investmentapproximately $1.7 billion for operations where Occidental exited or reduced its involvement in Plains Pipeline and other items.$3.4 billion related to the decline in commodity prices.
(e)The 20112016 amount includesincluded the gain on sale of the Occidental Tower in Dallas and a pre-tax chargenon-core specialty chemicals business. The 2015 amount represented a gain on sale of $163 million related to the premium on debt extinguishment.an idled facility.
(f)The 20132014 amount includesincluded a $55$633 million pre-tax charge for the estimated cost related to the employmentgain on sale of Occidental’s interest in BridgeTex Pipeline Company, LLC, and post-employment benefits for the Company's former Executive Chairman and terminationa $1.4 billion gain on sale of certain other employees and consulting arrangements.a portion of Occidental’s investment in Plains Pipeline.
(g)
The 20112016 amount includesincluded charges related to the termination of crude oil supply contracts.The 2015 amount included an impairment charge of $814 million related to the Century gas processing plant as a $144 million after-tax gain fromresult of SandRidge’s inability to provide volumes to the sale of the Argentine operations.  plant and meet its contractual obligations to deliver CO2.


Oil and Gas
Dollars in millions, except as indicated
  2013 2012 2011
Segment Sales $19,132
 $18,906
 $18,419
Segment Earnings (a)
 $7,894
 $7,095
 $10,241
(a)(h)The 20132016 amount includes pre-taxincluded charges of $607$541 million related to a reserve for doubtful accounts and $78 million loss on the distribution of the remaining CRC stock. The 2015 amount included a $227 million other-than-temporary loss on Occidental’s investment in California Resources. The 2014 amount included an $805 million impairment charge for the impairmentJoslyn oil sand project and a $553 million other-than-temporary loss on the investment in California Resources.
(i)Represents amounts attributable to income from continuing operations after deducting a non controlling interest amount of domestic non-producing acreage.$14 million in 2014. The 2012non controlling interest amount includes pre-tax chargeshas been netted in the midstream and marketing segment earnings.
(j)The 2016 and 2015 amounts included gains related to the Ecuador settlement. See Note 2 of $1.7 billion for the impairmentconsolidated financial statements. The 2014 amount included the results of domestic gas assets and related items.Occidental's California operations.

Oil and Gas
(in millions) 2016 2015 2014
Segment Sales $6,377
 $8,304
 $13,887
Segment Results      
Domestic $(1,552) $(4,151) $(2,381)
Foreign 965
 (3,747) 2,935
Exploration (49) (162) (126)
  $(636) $(8,060) $428

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, 20132016. 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 2013 2012 2011
United States      
Oil (MBBL)      
California 90
 88
 80
Permian Basin 146
 142
 134
Midcontinent and Other 30
 25
 16
Total 266
 255
 230
NGLs (MBBL)      
California 20
 17
 15
Permian Basin 39
 39
 38
Midcontinent and Other 18
 17
 16
Total 77
 73
 69
Natural gas (MMCF)      
California 260
 256
 260
Permian Basin 157
 155
 157
Midcontinent and Other 371
 410
 365
Total 788
 821
 782
Latin America (a)
      
Oil (MBBL) – Colombia 29
 29
 29
Natural gas (MMCF) – Bolivia 12
 13
 15
Middle East/North Africa      
Oil (MBBL)      
Dolphin 6
 8
 9
Oman 66
 67
 67
Qatar 68
 71
 73
Other 39
 40
 42
Total 179
 186
 191
NGLs (MBBL)      
Dolphin 7
 8
 10
Other —
 1
 —
Total 7
 9
 10
Natural gas (MMCF)      
Dolphin 142
 163
 199
Oman 51
 57
 54
Other 241
 232
 173
Total 434
 452
 426
Total Production (MBOE) (a,b)
 763
 766
 733
(See footnotes following the Average Realized Prices table)




23
Production per Day (MBOE) 2016 2015 2014
United States      
Permian Resources 124
 110
 75
Permian EOR 145
 145
 147
South Texas and Other 33
 73
 96
Total 302
 328
 318
Latin America 34
 37
 29
Middle East/North Africa      
Al Hosn 64
 35
 —
Dolphin 43
 41
 38
Oman 96
 89
 76
Qatar 65
 66
 69
Other 26
 72
 67
Total 294
 303
 250
Total Production (MBOE) (a)
 630
 668
 597
       
(See footnote following the Average Realized Prices table)
Production per Day from Ongoing Operations (MBOE) 2016 2015 2014
United States      
Permian Resources 124
 110
 75
Permian EOR 145
 145
 147
South Texas and Other 31
 42
 52
Total 300
 297
 274
Latin America 34
 37
 29
Middle East/North Africa      
Al Hosn 64
 35
 —
Dolphin 43
 41
 38
Oman 96
 89
 76
Qatar 65
 66
 69
Total 268
 231
 183
Total Production Ongoing Operations 602
 565
 486
Sold domestic operations 2
 31
 44
Sold or Exited MENA operations 26
 72
 67
Total Production (MBOE) (a)
 630
 668
 597
       
(See footnote following the Average Realized Prices table)

Production per Day by Products 2016 2015 2014
United States      
Oil (MBBL)      
Permian Resources 77
 71
 43
Permian EOR 108
 110
 111
South Texas and Other 4
 21
 29
Total 189
 202
 183
NGLs (MBBL)      
Permian Resources 21
 16
 12
Permian EOR 27
 29
 30
South Texas and Other 5
 10
 13
Total 53
 55
 55
Natural gas (MMCF)      
Permian Resources 158
 137
 120
Permian EOR 59
 37
 38
South Texas and Other 144
 250
 318
Total 361
 424
 476
Latin America      
Oil (MBBL) – Colombia 33
 35
 27
Natural gas (MMCF) – Bolivia 8
 10
 11
Middle East/North Africa      
Oil (MBBL)      
Al Hosn 12
 7
 —
Dolphin 7
 7
 7
Oman 77
 82
 69
Qatar 65
 66
 69
Other 7
 32
 28
Total 168

194

173
NGLs (MBBL)      
Al Hosn 20
 10
 —
Dolphin 8
 8
 7
Total 28

18

7
Natural gas (MMCF)      
Al Hosn 190
 109
 —
Dolphin 166
 158
 143
Oman 115
 44
 43
Other 114
 237
 236
Total 585

548

422
Total Production (MBOE) (a)
 630

668

597
       
(See footnote following the Average Realized Prices table)



Sales Volumes per Day 2013 2012 2011
United States      
Oil (MBBL) 266
 255
 230
NGLs (MBBL) 77
 73
 69
Natural gas (MMCF) 789
 819
 782
Latin America (a)
      
Oil (MBBL) – Colombia 27
 28
 29
Natural gas (MMCF) – Bolivia 12
 13
 15
Middle East/North Africa      
Oil (MBBL)      
Dolphin 6
 8
 9
Oman 68
 66
 69
Qatar 67
 71
 73
Other 38
 40
 38
Total 179
 185
 189
NGLs (MBBL)      
Dolphin 7
 8
 10
Other —
 1
 —
Total 7
 9
 10
Natural gas (MMCF) 434
 452
 426
Total Sales Volumes (MBOE) (a,b)
 762
 764
 731
(See footnotes following the Average Realized Prices table)
  2013 2012 2011
Average Realized Prices      
Oil Prices ($ per bbl)
      
United States $96.42
 $93.72
 $92.80
Latin America (a)
 $103.21
 $98.35
 $97.16
Middle East/North Africa $104.48
 $108.76
 $104.34
Total worldwide (a)
 $99.84
 $99.87
 $97.92
NGL Prices ($ per bbl)
      
United States $41.80
 $46.07
 $59.10
Middle East/North Africa $33.00
 $37.74
 $32.09
Total worldwide $41.03
 $45.18
 $55.53
Gas Prices ($ per Mcf)
      
United States $3.37
 $2.62
 $4.06
Latin America (a)
 $11.17
 $11.85
 $10.11
Total worldwide (a)
 $2.54
 $2.06
 $3.01
Production per Day by Products from Ongoing Operations 2016 2015 2014
United States      
Oil (MBBL)      
Permian Resources 77
 71
 43
Permian EOR 108
 110
 111
South Texas and Other 4
 6
 7
Total 189
 187
 161
NGLs (MBBL)      
Permian Resources 21
 16
 12
Permian EOR 27
 29
 30
South Texas and Other 5
 7
 9
Total 53
 52
 51
Natural gas (MMCF)      
Permian Resources 158
 137
 120
Permian EOR 59
 37
 38
South Texas and Other 133
 173
 210
Total 350
 347
 368
Latin America      
Oil (MBBL) – Colombia 33
 35
 27
Natural gas (MMCF) – Bolivia 8
 10
 11
Middle East/North Africa      
Oil (MBBL)      
Al Hosn 12
 7
 —
Dolphin 7
 7
 7
Oman 77
 82
 69
Qatar 65
 66
 69
Total 161
 162
 145
NGLs (MBBL)      
Al Hosn 20
 10
 —
Dolphin 8
 8
 7
Total 28
 18
 7
Natural gas (MMCF)      
Al Hosn 190
 109
 —
Dolphin 166
 158
 143
Oman 115
 44
 43
Total 471
 311
 186
Total Production Ongoing Operations 602

565

486
Sold domestic operations 2
 31
 44
Sold or Exited MENA operations 26
 72
 67
Total Production (MBOE) (a)
 630

668

597
       
(See footnote following the Average Realized Prices table)
Sales Volumes per Day by Products 2016 2015 2014
United States      
Oil (MBBL) 189
 202
 183
NGLs (MBBL) 53
 55
 55
Natural gas (MMCF) 361
 424
 476
Latin America      
Oil (MBBL) – Colombia 34
 35
 29
Natural gas (MMCF) – Bolivia 8
 10
 11
Middle East/North Africa      
Oil (MBBL)      
Al Hosn 12
 7
 —
Dolphin 7
 8
 7
Oman 77
 82
 69
Qatar 66
 67
 69
 Other 7
 36
 27
Total 169
 200
 172
NGLs (MBBL)      
Al Hosn 20
 10
 —
Dolphin 8
 8
 7
Total 28
 18
 7
Natural gas (MMCF) 585
 548
 422
Total Sales Volumes (MBOE) (a)
 632

674

598
       
(See footnote following the Average Realized Prices table)
Sales Volumes per Day by Products from Ongoing Operations 2016 2015 2014
United States      
Oil (MBBL) 189
 187
 161
NGLs (MBBL) 53
 52
 51
Natural gas (MMCF) 350
 347
 368
Latin America      
Oil (MBBL) – Colombia 34
 35
 29
Natural gas (MMCF) – Bolivia 8
 10
 11
Middle East/North Africa      
Oil (MBBL)      
Al Hosn 12
 7
 —
Dolphin 7
 8
 7
Oman 77
 82
 69
Qatar 66
 67
 69
Total 162
 164
 145
NGLs (MBBL)      
Al Hosn 20
 10
 —
Dolphin 8
 8
 7
Total 28
 18
 7
Natural gas (MMCF) 471
 311
 186
Total Sales Ongoing Operations 604
 567
 488
Sold domestic operations 2
 31
 44
Sold or Exited MENA operations 26
 76
 66
Total Sales Volumes (MBOE) (a)
 632
 674
 598
       
(See footnote following the Average Realized Prices table)



  2016 2015 2014
Average Realized Prices      
Oil Prices ($ per bbl)
      
United States $39.38
 $45.04
 $84.73
Latin America $37.48
 $44.49
 $88.00
Middle East/North Africa $38.25
 $49.65
 $96.34
Total worldwide $38.73
 $47.10
 $90.13
NGLs Prices ($ per bbl)
      
United States $14.72
 $15.35
 $37.79
Middle East/North Africa $15.01
 $17.88
 $30.98
Total worldwide $14.82
 $15.96
 $37.01
Gas Prices ($ per Mcf)
      
United States $1.90
 $2.15
 $3.97
Latin America $3.78
 $5.20
 $8.94
Total worldwide $1.53
 $1.49
 $2.55
(a)For all periods presented, excludes volumes and amounts from the Argentine operations sold in 2011 and classified as discontinued operations.
(b)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 2013 included pre-tax chargesresults were losses of $0.6 billion and $8.1 billion in 2016 and 2015, respectively, and income of $0.4 billion in 2014. The 2016 results for the impairment of domestic non-producing acreage while earnings in 2012 included pre-tax charges of $1.7 billion for the impairment of domestic gas assets and related items. In 2011, oil and gas segment earnings included pre-tax gains of $107 million, mainly comprised of the sales of Piceance and South Texas assets, and net charges of $35$61 million related to exploration write-offs in Libya and $29 million related to Colombia net worth tax, as well as a pre-tax gain of $22 million from the sale of an interest in a Colombian pipeline.Libya and exit from Iraq.
Oil and gas segment earnings, priorresults in 2015 included pre-tax impairment and related charges of $3.5 billion and $5.0 billion on domestic and international assets, respectively. Approximately $1.3 billion of the domestic impairment and related charges were due to the exit of Occidental’s operations in the Williston Basin, which was sold in November 2015 and in the Piceance Basin, which was sold in March 2016. The remaining domestic charges were due to the significant decline in the futures price curve as well as management’s decision not to pursue development activities associated with certain non-producing acreage. Internationally, the impairments and related charges were due to a combination of Occidental’s strategic plan to exit or reduce our exposure in certain Middle East and North Africa operations as well as the decline in the futures price curve, which have made certain projects in the region unprofitable. Earnings in 2014 included pre-tax charges of $5.3 billion related to the impairment charges in both years,of domestic and international assets and the gain from the sale of Hugoton assets.
Domestic oil and gas segment results were $8.5losses of $1.6 billion, $4.2 billion and $2.4 billion in 20132016, 2015 and 2014, respectively. Excluding the significant items noted above, the decrease in domestic oil and gas results in 2016, compared to $8.8 billion2015, reflected significantly lower realized oil prices, which had decreased by 13 percent in 2012.2016 compared to 2015 and higher DD&A rates. To a lesser extent, the lower 2016 results also reflected lower oil volumes due to the sale of non-core domestic operations. The year-over-year changedecrease in earnings resulted from higher domestic earnings, whichresults compared to 2015 were more thanpartially offset by lower cash operating expenses.
Similar to domestic results, and excluding the significant items noted above, the decrease in international earnings. Higher domestic earnings resulted from improvedin 2016, compared to 2015, reflected significantly
lower realized crude oil prices, which had decreased by 23 percent in the Middle East and gas realized prices, higher liquids volumes and lower operating costs,16 percent in Latin America partially offset by higherlower DD&A rates, stock price driven increases in equity compensation and lower NGL prices. Lower international earnings were caused by lower liquids sales volumes, lower oil prices and higher operating costs and DD&A rates in the Middle East/North Africa.rates.
Average production costs for 2013,2016, excluding taxes other than on income, were $13.76$10.76 per BOE, compared to $14.99
$11.57 per BOE for 2012. This2015. The decrease in average costs reflected the impactlower maintenance, workover and support costs as a result of improvements in operating efficiencies, especially in the domestic operations.
Average daily production volumes were 630,000 BOE and 668,000 BOE for 2016 and 2015, respectively, and included production from assets sold or exited of 28,000 BOE and 103,000 BOE for 2016 and 2015, respectively. Excluding production for assets sold or exited, average daily production volumes were 602,000 BOE and 565,000 BOE for 2016 and 2015, respectively. The increase in production from on-going operations mainly reflected higher production from Al Hosn Gas as it was not fully operational efficiency initiative wherein 2015 and higher production costs decreasedfrom Permian Resources, which increased its 2016 production by $3.00 per BOE13 percent compared to 2015. These increases were offset by lower production from $17.43 per BOESouth Texas and Other due to curtailed drilling.
In addition to the impairments and related charges noted above, the decrease in 2012domestic oil and gas segment results in 2015, compared to $14.43 per BOE in 2013. The domestic decrease was2014, reflected significantly lower crude oil, NGL and natural gas prices, partially offset by higher international production costs due to higher volumes from Iraq, which has high operating costs.
Average dailycrude oil and gas production volumes were 763,000 BOE for 2013, compared to 766,000 BOE for 2012. Occidental's daily domestic oil and NGL production increased by 11,000 BOE and 4,000 BOE, respectively, while gas production decreased by 33 MMcf. These results reflect Occidental's focus on oil drilling while reducing its drilling capital for gas in light of higher oil prices and lower gas prices in recent years. While domestic overall production improved by 9,000 BOE per day in 2013, international production was 12,000 BOE per dayoperating costs from lower mainly due toworkover and maintenance costs and lower cost recovery barrels in the Dolphin and Oman operations and field and port strikes in Libya. Average daily sales volumes were 762,000 BOE in the 12 months of 2013, compared to 764,000 BOE for the same period in 2012.
Oil and gas segment earnings, prior to the charges and other items noted above, were $8.8 billion in 2012 compared to $10.3 billion in 2011.DD&A expenses. The decrease in international earnings reflected lower NGL and gasrealized crude oil prices, and higher DD&A rates, maintenance activity, field support costs and exploration expense, partially offset by higher oil prices and domesticsales volumes.
Average daily oil and gas production volumes were 766,000668,000 BOE and 597,000 BOE for 2012,2015 and 2014, respectively, and included 103,000 BOE and 111,000 BOE of production from assets sold or exited in 2015 and 2014, respectively. Excluding production for assets sold or exited, average daily production volumes were 565,000 BOE and 486,000 BOE for 2015 and 2014, respectively. The increase in on going production reflected the commencement of production at Al Hosn in 2015 along with a 47 percent increase in production from Permian Resources.
Average production costs for 2015, excluding taxes other than on income, were $11.57 per BOE, compared to 733,000 BOE for 2011. Occidental's domestic production increased by 9 percent, while total company production increased by 5 percent. Dolphin's full cost recovery of pre-startup capital, which reduced production, was the only operation where PSCs and similar contracts had an appreciable effect on 2012


24


production volumes. Average daily sales volumes were 764,000$13.50 per BOE in the twelve months of 2012, compared to 731,000 BOE for the same period2014. The decrease in 2011.average costs reflected decreased activity in downhole maintenance and lower overall cost structure.

Chemical
In millions 2013 2012 2011
Segment Sales $4,673
 $4,580
 $4,815
Segment Earnings $743
 $720
 $861
(in millions) 2016 2015 2014
Segment Sales $3,756
 $3,945
 $4,817
Segment Results $571
 $542
 $420

Chemical segment earnings were $612$571 million, $542 million and $420 million for 2016, 2015 and 2014 respectively. Included in 2013, excluding the $131 million2016 earnings are a pre-tax gain on sale of $57 million from the Carbocloro investment, compared to $720sale of the Occidental Tower building in Dallas and a $31 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.
Chemical segment earnings were $720 million in 2012, compared to $861 million in 2011. The reduction was primarily the result of lower margins due to weaker economic conditions in Europe and Asia and increased competitive activity from these regions. The calcium chloride and potassium hydroxide businesses were also negatively impacted in 2012 by a mild winter and drought conditions in the United States.

Midstream, Marketing and Other
In millions 2013 2012 2011
Segment Sales $1,538
 $1,399
 $1,447
Segment Earnings $1,573
 $439
 $448

Midstream and marketing segment earnings in 2013 were $543 million, excluding the $1.0 billion pre-tax gain from the sale of a portionnon-core specialty chemicals business. Included in 2015 earnings are pre-tax asset impairments of $121 million and a pre-tax gain on sale of $98 million from the



sale of an investmentidled facility. Excluding these significant items, the decrease in Plains Pipeline and other items,2016 earnings, compared to $439 million in 2012. The 2013 results2015, reflected higher earnings in the pipeline and power generation businesses and improved marketing and trading performance. Marketing performance improved by $110 million, mainlylower PVC margins as a result of capturing regional crude price differentials by utilizing new pipelines providing access to the Gulf Coast refineries. These improvements werePVC pricing decreased with lower ethylene pricing, which was partially offset by lower incomeethylene and energy costs.
Segment earnings for 2014 included asset impairments of $149 million. Excluding these significant items, the decrease in the gas processing business due in part2015 earnings, compared to the plant turnarounds in the Permian Basin operations.2014 reflected lower caustic soda pricing and lower sales volumes across most products, offset by improved PVC margins resulting primarily from lower energy and ethylene costs.

Midstream and Marketing
(in millions) 2016 2015 2014
Segment Sales $684
 $891
 $1,373
Segment Results $(381) $(1,194) $2,564

Midstream and marketing segment results were losses of $0.4 billion and $1.2 billion in 2016 and 2015, respectively, and earnings of $2.6 billion in 20122014. Included in 2016 results was a $160 million charge related to the termination of crude oil supply contracts. Included in 2015 results were $439 million,impairments and related charges of $1.3 billion. Included in 2014 earnings were $2.0 billion of gains from the sale of BridgeTex Pipeline and part of Occidental's investment in Plains Pipeline. Excluding the significant items noted above, the decrease in 2016 results compared to $448 million in 2011.  The 2012 results2015 reflected lower marketing margins due to unfavorable contract pricing on long-term supply agreements as well as unfavorable Permian to Gulf Coast differentials, decreased throughput and lower realized NGLs pricing. Excluding the significant items noted above, the decrease in 2015 results, compared to 2014, primarily reflected lower marketing margins due to the narrowing of the Permian to Gulf Coast differentials, lower domestic gas processing earnings, partially offset by improved marketingincome due to lower NGL prices and trading performance.lower Dolphin Pipeline income and the decrease in Occidental's interest in Plains Pipeline.



SIGNIFICANT ITEMS AFFECTING EARNINGS
The following table sets forth, for the years ended December 31, 2013, 2012 and 2011, 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) 2013 2012 2011
OIL AND GAS      
Asset impairments and related items $(607) $(1,731) $—
Libya exploration write-off —
 —
 (35)
Gains on sale of Colombian pipeline interest —
 —
 22
Foreign tax —
 —
 (29)
Total Oil and Gas $(607) $(1,731) $(42)
CHEMICAL      
Carbocloro sale gain $131
 $—
 $—
Total Chemical $131
 $—
 $—
MIDSTREAM AND MARKETING      
Plains Pipeline sale gain and other $1,030
 $—
 $—
Total Midstream and Marketing $1,030
 $—
 $—
CORPORATE      
Charge for former employees and consultants $(55) $—
 $—
Litigation reserves —
 (20) —
Premium on debt extinguishments —
 —
 (163)
State income tax charge —
 —
 (33)
Tax effect of pre-tax adjustments (179) 636
 50
Discontinued operations, net of tax (a)
 (19) (37) 131
Total Corporate $(253) $579
 $(15)
(a)The 2011 amount includes a $144 million after-tax gain from the sale of the Argentine operations.

TAXES
Deferred tax liabilities, net of deferred tax assets of $1.6$2.3 billion, were $7.0$1.1 billion at December 31, 2013. The current portion of the deferred tax assets of $150 million is included in other current assets.2016. 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 2013 2012 2011
EARNINGS      
(in millions) 2016 2015 2014
SEGMENT RESULTS      
Oil and Gas $7,894
 $7,095
 $10,241
 $(636) $(8,060) $428
Chemical 743
 720
 861
 571
 542
 420
Midstream and Marketing(a) 1,573
 439
 448
 (381) (1,194) 2,564
Unallocated Corporate Items (533) (501) (709) (1,218) (764) (1,871)
Pre-tax income 9,677
 7,753
 10,841
Income tax expense      
Pre-tax (loss) income (1,664) (9,476) 1,541
Income tax (benefit) expense  
  
  
Federal and State 1,602
 694
 1,795
 (1,298) (2,070) (157)
Foreign 2,153
 2,424
 2,406
 636
 740
 1,842
Total income tax expense 3,755
 3,118
 4,201
Income from continuing operations $5,922
 $4,635
 $6,640
Total income tax (benefit) expense (662) (1,330) 1,685
Loss from continuing operations(a)
 $(1,002) $(8,146) $(144)
Worldwide effective tax rate 39% 40% 39% 40% 14% 109%
(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.



25


Occidental’s 2013Occidental's 2016 worldwide effective tax rate was 3940 percent, slightly lowerwhich is higher than 2012the 2015 rate mainly due to proportionately higherthe mix of domestic pre-taxoperating losses and foreign operating income, in 2013. The 2012tax credits and tax benefits resulting from the write off of exploration blocks. Excluding the impact of impairments and other nonrecurring items, Occidental’s worldwide effective tax rate was higher than 2011 due to proportionately higher foreign pre-tax income in 2012.for 2016 would be 24 percent.
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 $134$116 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 2013 2012 2011
(in millions) 2016 2015 2014
Net sales $24,455
 $24,172
 $23,939
 $10,090
 $12,480
 $19,312
Interest, dividends and other income $106
 $81
 $180
 $106
 $118
 $130
Gain on sale of equity investments $1,175
 $—
 $—
Gain on sale of equity investments and other assets $202
 $101
 $2,505

The increasedecrease in net sales in 2013,2016, compared to 2012,2015, was mainly due to improved domesticthe decline in average worldwide realized oil prices in 2016 and gasa decline in worldwide production as Occidental exited non-core areas. Average worldwide realized oil prices and higher liquids volumes, partially offsetfell by lower international liquids volumes and oil prices.approximately 18 percent from 2015 to 2016.
The increasedecrease in net sales in 2012,2015, compared to 2011,2014, was due to highera significant decline in worldwide oil, volumesNGLs and gas prices, partially offset by lowerhigher domestic and international crude oil volumes. Average WTI and Brent



prices fell by nearly 50 percent and NYMEX gas and NGL prices and lower prices and volumes across most chemical products.fell by over 35 percent in 2015 compared to 2014 prices.
Price and volume changes in the oil and gas segment generally represent the majority of the change in oil and gas segment sales which is a substantially larger portion of the overall change in net sales than the chemical and midstream and marketing segments.
The 20132016 gain on sale included the sale of equity investments relates toPiceance and South Texas oil and gas properties, the pre-tax gains fromOccidental Tower building in Dallas, and a non-core specialty chemicals business. The 2015 gain on sale included $98 million for the salessale of an idled chemical facility. The 2014 gain 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 Carbocloro investment.sale of Hugoton properties.

Expense Items
In millions 2013 2012 2011
(in millions) 2016 2015 2014
Cost of sales $7,562
 $7,844
 $7,385
 $5,189
 $5,804
 $6,803
Selling, general and administrative and other operating expenses $1,801
 $1,602
 $1,523
 $1,330
 $1,270
 $1,503
Depreciation, depletion and amortization $5,347
 $4,511
 $3,591
 $4,268
 $4,544
 $4,261
Asset impairments and related items $621
 $1,751
 $—
 $825
 $10,239
 $7,379
Taxes other than on income $749
 $680
 $605
 $277
 $343
 $550
Exploration expense $256
 $345
 $258
 $62
 $36
 $150
Interest and debt expense, net $118
 $130
 $298
 $292
 $147
 $77

Cost of sales decreased in 2013, compared to 2012,2016 from the prior year due primarily to lower oil and gas operatingmaintenance costs partially offset by higherand lower chemical feedstock and energy costs. Cost of sales decreased in 2015, compared to 2014, due to lower energy and feedstock costs in the chemical segment. The reduction in oil and gas operating costs
reflected a wide range of initiatives, including high-grading of service rigs, improved job scheduling and liquids usage and handling, optimizing field supervision and reduced consumption ofsegment, lower fuel power and field rental equipment.
Cost of sales increased in 2012, compared to 2011, due to higher oil and gas volumes and operating costs, mostly resulting from higher maintenance activity and field support costs, partially offset by lower feedstock and energy costs in the chemical segment.power generation operations and lower worldwide production costs, including workovers and downhole maintenance costs.
Selling, general and administrative and other operating expenses increased in 20132016 compared to 2015, due to highera lower compensation and employee-related costs,accruals in particular higher equity compensation due to higher stock prices and higher headcount in 2013 compared to 2012, as well as the charge2015 related to the employment and post-employment benefits for Occidental's former Executive Chairman and termination of certain other employees and consulting arrangements.decision not to pay bonuses.
Selling, general and administrative and other operating expenses decreased in 2015 compared to 2014, due to lower compensation expense.
DD&A expense decreased in 2016, compared to 2015, due to lower volumes from the exited non-core oil and gas operations and lower DD&A rates in the Middle East. DD&A expense increased in 20122015, compared to 2014 due to higher headcount,production volumes partially offset by lower equity compensation expenseDD&A rates.
In 2016, Occidental incurred impairment and the Colombia net worth tax,related items charges of $825 million, of which increased the 2011 costs.
DD&A increased in each year from 2011 to 2013, generally due to higher DD&A rates and,$541 million related to a lesser extent,reserve for doubtful accounts and $160 million for the changestermination of crude oil supply contracts, $78 million related to the disposal of CRC stock and $61 million related to exits from Libya and Iraq.
Asset impairments and related items in volumes in the2015 of $10.2 billion included charges of $3.5 billion related to domestic oil and gas segment.assets due to Occidental’s exit from the Williston and Piceance basins as well as the decline in the futures price curve and management’s decision not to pursue activities associated with certain non-producing acreage.
International oil and gas charges of $5.0 billion were due to a combination of Occidental’s strategic plan to exit or reduce its exposure in certain Middle East and North Africa operations as well as the decline in the futures price curve, which have made certain projects in the region unprofitable. Midstream charges of $1.3 billion included the impairment of Occidental’s Century gas processing plant as a result of SandRidge’s inability to provide volumes to the plant and meet their contractual obligations to deliver CO2. Occidental recorded an other-than-temporary loss of $227 million for its available for sale investment in California Resources.
Asset impairments and related items in 20132014 of $621$7.4 billion included $2.8 billion in the Williston basin, $904 million were mostly related to the impairment of certain non-producingOccidental's gas and NGLs assets, $889 million for other domestic oilacreage and gas acreage.
$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 related itemsan other than temporary loss of $553 million for the available for sale investment in 2012 were almost all in Midcontinent, over 90 percent of which were related to natural gas properties that were acquired more than five years ago on average when gas prices were above $6 per Mcf.California Resources stock.
Taxes other than on income increaseddecreased in each year2016 from 20112015 due primarily to 2013,lower production taxes, which are directly tied to lower commodity prices. Taxes other than on income in 2015 decreased from 2014 due primarily to higher domesticlower oil, volumes and oilNGL and gas prices. During the period from 2011 to 2013, these expenses also reflected increasing domesticprices, which resulted in lower ad valorem taxes resulting from higher property values and California greenhouse gas costs.
Interest and debt expense, net, in 2011, included a $163 million early debt extinguishment charge.severance taxes.

Other Items
Income/(expense) (in millions) 2013 2012 2011 2016 2015 2014
Provision for income taxes $(3,755) $(3,118) $(4,201)
(Provision for) benefit from income taxes $662
 $1,330
 $(1,685)
Income from equity investments $395
 $363
 $382
 $181
 $208
 $331
Discontinued operations, net $(19) $(37) $131
 $428
 $317
 $760

Provision forThe benefit from income taxes increaseddecreased in 2013,2016 from the prior year as a result of a lower net loss in 2016, compared to 2012, due to higher pre-tax income, partially offset by a slightly lower effective tax rate.2015, which reflected significant impairments and related items charges. The lower tax rate was due to higher proportional domestic pre-tax income in 2013, compared to 2012.
Provisionprovision for income taxes decreased in 2012,2015, compared to 2011,2014, due to the pre-tax loss in 2015 as a result of the lower pre-taxprice environment and impairments and related charges.
The decline in income partially offset byfrom equity investments in 2016 from 2015 is the result of lower Dolphin gas sales. The decline in 2015 from 2014 is a slightly higher effective tax rate. The higher tax rate was due to higher proportional foreign pre-tax incomeresult of the lower Dolphin gas sales, Occidental's reduced ownership in 2012, compared to 2011.Plains Pipeline and the expiration of Occidental's contract in Yemen Block 10, where Occidental held an equity interest.


26


Discontinued operations, net in 2011, included2016 and 2015 of $428 and $317 million, respectively, primarily include settlement payments by the $144 million after-tax gain recorded from the saleRepublic of Ecuador. See Note 2 of the Argentine operations.Consolidated Financial Statements.




CONSOLIDATED ANALYSIS OF FINANCIAL POSITION
The changes in select components of Occidental’s balance sheet are discussed below:

Balance Sheet Components
In millions 2013 2012
(in millions) 2016 2015
CURRENT ASSETS        
Cash and cash equivalents $3,393
 $1,592
 $2,233
 $3,201
Restricted cash —
 1,193
Trade receivables, net 5,674
 4,916
 3,989
 2,970
Inventories 1,200
 1,344
 866
 986
Assets held for sale —
 141
Other current assets 1,056
 1,640
 1,340
 911
Total current assets $11,323
 $9,492
 $8,428
 $9,402
        
Investments in unconsolidated entities $1,459
 $1,894
 $1,401
 $1,267
Available for sale investment $—
 $167
Property, plant and equipment, net $55,821
 $52,064
 $32,337
 $31,639
Long-term receivables and other assets, net $840
 $760
 $943
 $934
        
CURRENT LIABILITIES        
Current maturities of long-term debt $—
 $600
 $—
 $1,450
Accounts payable 5,520
 4,708
 3,926
 3,069
Accrued liabilities 2,556
 1,966
 2,436
 2,213
Domestic and foreign income taxes 358
 16
Liabilities of assets held for sale —
 110
Total current liabilities $8,434
 $7,290
 $6,362
 $6,842
        
Long-term debt, net $6,939
 $7,023
 $9,819
 $6,855
Deferred credits and other liabilities-income taxes $7,197
 $6,039
 $1,132
 $1,323
Deferred credits and other liabilities-other $3,501
 $3,810
 $4,299
 $4,039
Stockholders’ equity $43,372
 $40,048
 $21,497
 $24,350

Assets
See "Liquidity and Capital Resources — Cash Flow Analysis" for discussion of the change in cash and cash equivalents.equivalents and restricted cash.
The increase in trade receivables, net, was due to higherthe result of improved oil and gas prices and higher equity and third-party oil volumes at the end of 2013,2016, compared to the end of 2012.2015. Average December WTI and Brent prices were below $40.00 per barrel in 2015 compared to over $50.00 per barrel in 2016. Inventories decreased as a result of lower materials and supplies inventories in the oil and gas segment. The decrease in inventories primarily resulted from lower storage inventories. The decrease in otherassets held for sale is the result of the sale of Piceance oil and gas properties and the Dallas Tower office building. Other current assets mainly reflectedincreased as a result of receivables recorded for federal and state tax refunds anticipated on the collection of a tax refund in 2013.net loss carryback. The decreaseincrease in investments in unconsolidated entities was due to contributions to the sales of a portionethylene cracker joint venture, which were partially offset by distributions from Dolphin Energy and Plains All American Pipeline Company. The decrease in the available for sale investment is due to the complete distribution of Occidental's retained interest in Plains Pipeline andCalifornia Resources as a special stock dividend in the investment in Carbocloro.first quarter of 2016. The increase in PP&E, net, was due to capital expenditures and the fourth quarter Permian acquisitions, of oil and gas properties,which were partially offset by DD&A and asset impairments.&A.

Liabilities and Stockholders' Equity
The decrease in current maturities of long-term debt was due to the redemption of the $600 million senior notes that matured in 2013. The increase in accounts payable reflected higher marketing payables as a result of higher oil and gas prices higher equity and third-party oil volumes and higher capital expenditures at the end of 2013,2016 compared to the end of 2012. The December 31, 2013 accrued liability balance included2015. Liabilities of assets held for sale were transferred with the accrualsale of the fourthPiceance properties in the first quarter 2013 dividend to be paid in 2014, while the 2012 balance did not include a dividend accrual due toof 2016.
 
The decrease in deferred credits and other liabilities-income taxes was due to the accelerated paymentdecrease in the difference between the book and tax basis of the fourth quarter dividend during that year.Occidental's oil and gas properties. The increase in domestic and foreign income taxes reflected the lack of a 2012 accrual resulting from a refund due at the end of that year. The increase in deferred and other domestic and foreign income taxes was mainly due to faster tax depreciation on capital expenditures. The decrease in deferred credits and other liabilities was primarily due to the reduction of pensionadditional asset retirement obligation (ARO) recorded related to the Permian acquisitions and postretirement plan liabilities.newly drilled wells and additional environmental liabilities recorded for Maxus indemnified sites. The increasedecrease in stockholders' equity reflected net income for 2013 and reduced pension and postretirement obligations, partially offset bythe distribution of cash dividends and treasury stock purchases.the 2016 net loss.

LIQUIDITY AND CAPITAL RESOURCES
At December 31, 20132016, Occidental had approximately $3.4$2.2 billion in cash and cash equivalents. While aA substantial majority of this cash is held and available for use in the United States,Occidental believes the cash in foreign jurisdictions can be brought to the United States without paying significant taxes.States. 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.
Occidental hasutilized the remaining restricted cash balance resulting from the spin-off of California Resources in the first quarter of 2016 to retire debt and pay dividends.
In November 2016, Occidental issued $1.5 billion of senior notes, comprised of $750 million of 3.0-percent senior notes due 2027 and $750 million of 4.1-percent senior notes due 2047. Occidental received net proceeds of $1.49 billion. Interest on the senior notes is payable semi-annually in arrears in February and August each year for each series of senior notes beginning August 15, 2017. Occidental will use the proceeds for general corporate purposes.
In May and June 2016, respectively, Occidental utilized part of the proceeds from the April 2016 senior note offering (described below) to exercise the early redemption option on $1.25 billion of 1.75-percent senior notes due in the first quarter of 2017 and to retire all $750 million of 4.125-percent senior notes that matured in June 2016.
In April 2016, Occidental issued $2.75 billion of senior notes, comprised of $0.4 billion of 2.6-percent senior notes due 2022, $1.15 billion of 3.4-percent senior notes due 2026 and $1.2 billion of 4.4-percent senior notes due 2046. Occidental received net proceeds of approximately $2.72 billion. Interest on the senior notes is payable semi-annually in arrears in April and October of each year for each series of senior notes, beginning on October 15, 2016. Occidental used a portion of the proceeds to retire debt in May and June 2016, and will use the remaining proceeds for general corporate purposes.
In February 2016, Occidental retired $700 million of 2.5-percent senior notes that had matured.
In June 2015, Occidental issued $1.5 billion of debt that was comprised of $750 million of 3.50-percent senior unsecured notes due 2025 and $750 million of 4.625-percent senior unsecured notes due 2045. Occidental received net proceeds of approximately $1.48 billion. Interest on the notes is payable semi-annually in arrears in June and December of each year for both series of notes, beginning on December 15, 2015.
In August 2014, Occidental entered into a new five-year, $2.0 billion bank credit facility (Credit Facility) with a $2.0in order to replace its previous $2.0 billion commitment expiring bank credit facility, which was scheduled to expire in October 2016. No amounts have been drawn under thisThe 2014 Credit Facility. Up to $1.0 billion of the Credit



Facility is available in the form of letters of credit. Borrowings under the Credit Facility bear interest at various benchmark rates, including LIBOR, plus a margin based on Occidental's senior debt ratings. Additionally, Occidental paid average annual facility fees of 0.08 percent in 2013 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 dodoes 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 Credit Facility during 2016 or that would permit lenders to terminate their commitments or accelerate debt.2015 and no amounts were outstanding as of December 31, 2016.
As of December 31, 2013,2016, under the most restrictive covenants of its financing agreements, Occidental had substantial capacity for additional unsecured borrowings, the payment of cash dividends and other distributions on, or acquisitions of, Occidental stock. Occidental also has a shelf registration statement that facilitates future issuances of securities.
Occidental expects to fund its liquidity needs, including future dividend payments, through cash on hand, cash generated from time to time, may accessoperations, monetization of non-core assets or investments and has accessed debt markets for general corporate purposes, including acquisitions. At this time, Occidental does not anticipate any need for such funding.through future borrowings, and if necessary, proceeds from other forms of capital issuance.



27


Cash Flow Analysis
In millions 2013 2012 2011
Cash provided by operating activitiesCash provided by operating activities     
(in millions) 2016 2015 2014
Operating cash flow from continuing operations $2,519
 $3,254
 $8,871
Operating cash flow from discontinued operations, net of taxes 864
 97
 2,197
Net cash provided by operating activities $12,927
 $11,312
 $12,281
 $3,383
 $3,351
 $11,068

Net income increased by $1.3 billion in 2013 compared to 2012, while cashCash provided by operating activities increasedfrom continuing operations in 2016 decreased $0.7 billion to $2.5 billion, from $3.3 billion in 2015. Operating cash flows were negatively impacted by $1.6 billion. These differences reflectlower worldwide average realized oil prices in the first half of 2016, which on a year-over-year basis declined 18 percent. The effect of lower commodity prices was partially offset by lower operating costs, especially in the oil and gas segment where year over year production costs decreased by 7 percent. Cash flows from continuing operations in 2016 also included collections of $325 million of federal and state tax refunds. The usage of working capital changes andin 2016 reflected an increase in receivables as oil prices were much higher at the end of 2016, compared to the end of 2015. Operating cash flows from discontinued operations reflected the collection of a tax refund increased cash flowthe Ecuador settlement.
Cash provided by operating activities from continuing operations by $1.8in 2015 decreased $5.6 billion to $3.3 billion, from $8.9 billion in 2013, compared to 2012, offset2014. Operating cash flows were negatively impacted by the $1.2 billion gainslower worldwide realized oil, NGLs, and natural gas prices throughout 2015, which on sales of equity investments in 2013a year-over-year basis declined 48 percent, 57 percent, and $0.3 billion42 percent, respectively. The effect of lower non-cash charges. The most significant changes in non-cash charges from 2012 to 2013 were lower asset impairments by $1.1 billion,commodity prices was partially offset by higher DD&A expenses by $0.8 billion.production and lower operating costs. The 2013 net income included gains on the salesusage of equity investments for which cash is reported as an investing activity.
The increaseworking capital in operating cash flows in 2013, compared to 2012, also2015 reflected lower domestic oilrealized prices that impacted receivable collections and gaspayments related to higher capital and operating costs, 3-percentspending accrued in the fourth quarter of 2014 and 29-percent higher domestic prices for oil and gas, respectively, and higher domestic oil volumes, partially offset by the Middle East/North Africa's lower oil volumes and prices and higher operating costs.paid in 2015.
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 flowflows than the changes
in oil and gas product prices, andsales volumes and operating costs.
Although net income decreased by $2.2 billion for the 12 months ended December 31, 2012, compared to the same period of 2011, net cash provided by operating activities only decreased by $1.0 billion for this period. Compared to 2011, net income in 2012 included much larger non-cash charges, which reduced net income but not cash provided by operating activities. These non-cash charges mainly comprised asset impairments and higher DD&A. Working capital changes in 2012 further reduced cash flow from operations by approximately $0.8 billion, compared to 2011.
Additionally, operating cash flows in 2012, compared to 2011, reflected lower domestic gas and worldwide NGL prices, by 35 percent and 19 percent, respectively, and higher maintenance activity and field support costs, partially offset by higher domestic oil volumes and 2-percent higher worldwide oil prices. The positive cash-flow impact of the oil price change was more than offset by the negative effect of significant declines in gas and NGL prices. The decrease in operating cash flows in 2012, compared to 2011, also reflected lower chemical margins, primarily due to weaker economic conditions in Europe and Asia.
The impact of the chemical and the midstream and marketing segments oncash flows are significantly smaller and their overall cash flows isare generally less significant than the impact of the oil and gas segment because the chemical and midstream and marketing segments are significantly smaller.
Other non-cash charges to income in 2013, 2012 and 2011 included charges for stock-based compensation plans and asset retirement obligation accruals.
Operating cash flows for discontinued operations include the Argentine operations through the date they were sold in 2011.segment.
Cash used by investing activities            
(in millions) 2013 2012 2011 2016 2015 2014
Capital expenditures            
Oil and Gas $(7,045) $(8,220) $(6,145) $(1,978) $(4,442) $(6,533)
Chemical (424) (357) (234) (324) (254) (314)
Midstream and Marketing (1,404) (1,558) (1,089) (358) (535) (1,983)
Corporate (164) (91) (50) (57) (41) (100)
Total (9,037) (10,226) (7,518) (2,717) (5,272) (8,930)
Other investing activities, net 844
 (2,429) (4,955) (2,025) (151) 2,686
Net cash used by investing activities – continuing operations (8,193) (12,655) (12,473) (4,742) (5,423) (6,244)
Investing cash flow from discontinued operations —
 —
 2,570
 —
 —
 (2,226)
Net cash used by investing activities $(8,193) $(12,655) $(9,903) $(4,742) $(5,423) $(8,470)

Compared to $10.2Occidental’s net capital expenditures declined by $2.7 billion in 2012, 2016 to $2.9 billion, after contributions to the OxyChem Ingleside facility which is included in other investing activities. The decline was a result of the oil and gas budget reduction due to lower commodity price environment and reductions in spending on long-term projects such as the OxyChem Ingleside facility, which is expected to come on line in early 2017.
Occidental's net capital expenditures for 2013 were $8.8declined $3.1 billion in 2015 to $5.6 billion, after $0.2 billion in BridgeTex partner contributions to the OxyChem Ingleside facility which arewas included in financingother investing activities. The decrease in capital expendituresdecline was the result of $1.4 billion from 2012 to 2013 was mainly due to the $1.2 billion decreaselower spending 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 decreasenon-core operations in the midstreamUnited States and marketingMiddle East and reduced expenditures on long-term projects coming on line at the end of 2014.
While the 2017 environment remains challenging, Occidental remains committed to allocating capital expenditures was due to lower spending for the Al Hosn gas project, partially offset by increased spending for BridgeTex.
Occidental’s netonly its highest return projects. Occidental's 2017 capital spending is expected to increase in 2014 to approximately $10.2 billion, compared to $8.8 billion in 2013. Approximately $1.2 billion of the increase will be in the oil and gas segment and includes additional capital allocatedrange of $3.0 billion to $3.6 billion.
In 2016, cash flows used in other investing activities of $2.0 billion is comprised primarily of the California andacquisition of acreage in the Permian Basin operationsin October 2016.
In 2015, cash flows used in other investing activities of approximately $0.4 billion each. Those operations will use the capital almost entirely for additional oil drilling to accelerate their development plans and production growth. An additional $0.1 billion is expected to be spent on these and other domestic assets for facilities projects that were deferredcomprised primarily of changes in 2013. Occidental also expects to continue to fund growth opportunities in key international assets, mainly Oman and Qatar, which will get approximately $0.3 billion of the increased capital, and complete the Al Hosn gas project, where the capital expenditures are expected to be lower in 2014 compared to 2013. Exploration capital is expected to increaseaccrual and asset purchases offset by approximately $0.1 billion, in part due to deferred spending in 2013. The total midstream and marketing capital will increase by approximately $0.1 billion for the BridgeTex Pipeline and the chemical capital will increase slightly due to the ethylene cracker project announced in 2013. The 2014 capital program is expected to be approximately 80 percent in oil and gas, 7 percent in the Al Hosn gas project,


28


7 percent in domestic midstream and marketing and the remainder in the chemical segment.
The 2013 other investing activities, net amount included $1.6 billion of cash received from the sales of a portion of Occidental's interest in Plains Pipelineequity investments and the investment in Carbocloro, partially offset by $0.6 billion in cash paymentsassets.
Capital commitments for the acquisitions of businesses and assets, largely consisting of various interests in domestic oil and gas properties.
The increase in capital expenditures of $2.7 billion from 2011 to 2012 was mainly due to the $2.1 billion increase in oil and gas expenditures, a majority of which was in domestic properties, such as Permian and California, as well as increases throughout the Middle East.  The increaselong-term projects currently under construction in the midstream and marketing capital expenditureschemicals segment in 2017 are planned to be approximately $140 million.
Cash provided (used) by financing activities     
(in millions) 2016 2015 2014
Financing cash flow from continuing operations $391
 $1,484
 $(2,326)
Financing cash flow from discontinued operations —
 —
 124
Net cash provided (used) by financing activities $391
 $1,484
 $(2,202)




Cash provided by financing activities in 2016 was almost entirely due$0.4 billion, as compared to the Al Hosn gas project.
The 2012 other investingcash provided by financing activities net amountin 2015 of $1.5 billion. Financing activities in 2016 included $2.5 billion in cash payments for the acquisitionsproceeds from long term debt of businesses and assets, largely consisting of various interests in domestic oil and gas properties in the Permian Basin, the Williston Basin, California and South Texas. Also included in 2012 investing activities was approximately $190 million of cash dividends received as investment returns.
The 2011 other investing activities, net amount included $4.9 billion in cash payments for the acquisitions of businesses and assets, including various interests in domestic oil and gas properties, in operated, producing and non-producing properties in California and the Permian and Williston basins for approximately $2.4 billion, properties in South Texas for $1.8$4.2 billion and $0.5payments of long term debt of $2.7 billion. Occidental used restricted cash of $1.2 billion for Occidental’s share of pre-acquisition development expenditures incurredto pay dividends and retire debt.
Cash provided by the Al Hosn gas project.
Investing cash flow from discontinued operations included $2.6financing activities in 2015 was $1.5 billion, of cash received from the sale of the Argentine operations in 2011.
Commitments at December 31, 2013, for major fixed and determinable capital expenditures were approximately $2.1 billion, which will be due in 2014 and beyond.  Occidental expectsas compared to fund its commitments and capital expenditures with cash from operations.
In millions 2013 2012 2011
Net cash used by financing activities $(2,933) $(846) $(1,175)

The 2013 net cash used by financing activities in 2014 of $2.2 billion. Financing activities in 2015 included $0.7 billionproceeds from long term debt of $1.5 billion. Occidental used to retire debt and $0.2 billionrestricted cash of contributions received from a noncontrolling interest. Common stock dividends paid decreased by $0.6$2.8 billion to $1.6 billion in 2013, due to the accelerated payment in 2012 of that year's fourth quarter dividend. In addition, purchases ofpay dividends and purchase 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.
stock.
In 2012 common stock dividends paid increased by $0.7 billion to $2.1 billion compared to 2011, which included the accelerated payment of the fourth quarter dividend. In addition, purchases of treasury stock increased from $0.3 billion in 2011 to $0.6 billion in 2012. The 2012 cash flows also reflected $1.7 billion of proceeds from the issuance of unsecured notes.
The 2011 amount included net proceeds of approximately $2.1 billion from the issuance of senior unsecured notes and cash use of $1.5 billion to retire long-term debt.


OFF-BALANCE-SHEET ARRANGEMENTS
The following is a description of the business purpose and nature of Occidental's off-balance-sheet arrangements.
Guarantees
Occidental has guaranteed certainits 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, 20132016, Occidental’s guarantees were not material and a substantial majority consisted of limited recourse guarantees on approximately $354$296 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.
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."


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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, 20132016.
Contractual Obligations
(in millions)
   Payments Due by Year   Payments Due by Year
Total 2014 
2015
and
2016
 
2017
and
2018
 
2019
and
thereafter
 Total 2017 
2018
and
2019
 
2020
and
2021
 
2022
and
thereafter
On-Balance Sheet                    
Long-term debt (Note 5) (a)
 $6,964
 $—
 $1,450
 $1,750
 $3,764
 $9,907
 $—
 $616
 $1,249
 $8,042
Other long-term liabilities (b)
 1,874
 242
 397
 264
 971
 2,218
 760
 323
 294
 841
Off-Balance Sheet                    
Operating leases (Note 6) 1,166
 141
 219
 217
 589
 1,274
 255
 364
 186
 469
Purchase obligations (c)
 10,024
 2,977
 2,656
 1,371
 3,020
 8,938
 1,649
 2,037
 1,450
 3,802
Total $20,028
 $3,360
 $4,722
 $3,602
 $8,344
 $22,337
 $2,664
 $3,340
 $3,179
 $13,154
(a)
Excludes unamortized debt discount and interest on the debt.  As of December 31, 2013,2016, interest on long-term debt totaling $1.4$5.1 billion is payable in the following years (in millions): 20142017 - $218, 2015$362, 2018 and 20162019 - $402, 2017$705, 2020 and 20182021 - $292, 2019$640, 2022 and thereafter - $505.
$3,399.
(b)Includes obligations under postretirement benefit and deferred compensation plans, as well as certainaccrued transportation commitments and other 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, pipeline and pipelineprocessing capacity, drilling rigs and services, CO2, 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 3.1-percent3.7 percent discount rate.


Delivery Commitments
Occidental has made commitments to certain refineries and other buyers to deliver oil, natural gas and NGLs. The total amountdomestic volumes contracted to be delivered, a substantial majoritywhich are not presented in Note 7 of which is in the United States, isconsolidated financial statements, are approximately 7381 million barrels of oil through 2019, 83 billion cubic feet2025, 5 Bcf of gas through 20162017 and 1511 million barrels of NGLs through 2015.2018. 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
OPCOccidental 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. OPCOccidental 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 OPCOccidental 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.
In accordance with applicable accounting guidance, 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. In Note 8, Occidental has disclosed its reserve balances for environmental matters.remediation matters that satisfy these criteria. Reserve balances for matters, other mattersthan environmental remediation, that satisfy these criteria as of December 31, 20132016 and 2012,December 31, 2015 were not material to Occidental'sOccidental’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 disclosedoutstanding lawsuits, claims and proceedings and discloses its estimable range of reasonably possible additional losses for sites where it is a participant in environmental remediation. Occidental believes that other reasonably possible losses for non-environmental matters 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 underOccidental reassesses the caption "Environmental Liabilitiesprobability and Expenditures" below.estimability of contingent losses as new information becomes available.

Tax Matters
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 whichthat are subject to IRS review. Taxable years from 20002002 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'sOccidental’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,
Indemnities to Third Parties
Occidental, 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, 2013,2016, 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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ENVIRONMENTAL LIABILITIES AND EXPENDITURES
Occidental’s operations are subject to stringent federal, state, local and foreign laws and regulations related to improving or maintaining environmental quality. Occidental’s environmental compliance costs have generally increased over time and are expected to rise in the future. Occidental factors environmental expenditures for its operations into its business planning process as an integral part of producing quality products responsive to market demand.

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

ENVIRONMENTAL REMEDIATION
As of December 31, 2013,2016, Occidental participated in or monitored remedial activities or proceedings at 157147 sites. The following table presents Occidental’s environmental remediation reserves as of December 31, 2013, 20122016, 2015 and 2011,2014, the current portion of which is included in accrued liabilities ($131 million in 2016, $70 million in 2015, and $79 million in 2014) and the remainder in deferred credits and other liabilities — other ($739 million in 2016, $316 million in 2015, and $255 million in 2014). 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)(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
 2013 2012 2011
($ amounts
in millions)
 2016 2015 2014
 
# of
Sites
 
Reserve
Balance
 
# of
Sites
 
Reserve
Balance
 
# of
Sites
 
Reserve
Balance
 
# of
Sites
 
Reserve
Balance
 
# of
Sites
 
Reserve
Balance
 
# of
Sites
 
Reserve
Balance
NPL sites 31
 $25
 35
 $54
 36
 $63
 33
 $461
 34
 $27
 30
 $23
Third-party sites��74
 83
 75
 84
 73
 88
 68
 163
 66
 128
 67
 101
Occidental-operated sites 20
 118
 22
 123
 22
 120
 17
 106
 18
 107
 17
 107
Closed or non-operated Occidental sites 32
 104
 29
 83
 29
 89
 29
 140
 31
 124
 31
 103
Total 157
 $330
 161
 $344
 160
 $360
 147

$870
 149
 $386
 145
 $334

As of December 31, 2013,2016, Occidental’s environmental reserves exceeded $10 million each at 1016 of the 157147 sites



described above, and 10888 of the sites had reserves from $0 to $1 million each.
As of December 31, 2013, two2016, three sites — the Diamond Alkali Superfund Site and a former chemical plant in Ohio(both of which are indemnified by Maxus Energy Corporation, as discussed further below), and a landfill in western New York owned by Occidental and a former facility inWestern New York — accounted for 6095 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 14The reserve balance above includes 17 NPL sites subject to indemnification by Maxus.
Four of the remaining NPL sites.
As of December 31, 2013, Maxus has also retained the liability and is indemnifying Occidental for 8 of the 74 third-party sites. Three of the remaining 6668 third-party sites —a Maxus-indemnified chrome site in New Jersey, a former copper mining and smelting operation in Tennessee, a containment and removal project in Tennesseean active plant outside of the United States and an active refinery in Louisiana where Occidental reimburses the current owner for certain remediation activities — accounted for 5253 percent of Occidental’s reserves associated with these sites. The reserve balance above includes 9 third-party sites subject to indemnification by Maxus.
FourThree sites — chemical plants in Kansas, Louisiana, and New York and a group of oil and gas properties in the southwestern United States —Texas accounted for 6148 percent of the reserves associated with the Occidental-operated sites.
FourSix other sites — a landfill in western New York, former chemical plants in Tennessee, Delaware, Washington and DelawareCalifornia, and a closed coal mine in Pennsylvania — accounted for 6469 percent of the reserves associated with closed or non-operated Occidental sites.
When Occidental acquired Diamond Shamrock Chemicals Company (DSCC) in 1986, Maxus Energy Corporation (Maxus), currently a subsidiary of YPF S.A. (YPF), agreed to indemnify Occidental for a number of environmental sites, including the Diamond Alkali Superfund Site (Site) along a portion of the Passaic River. On June 17, 2016, Maxus and several affiliated companies filed for Chapter 11 bankruptcy in Federal District Court in the State of Delaware. Prior to filing for bankruptcy, Maxus defended and indemnified Occidental in connection with clean-up and other costs associated with the sites subject to the indemnity, including the Site. Occidental is pursuing Maxus and its parent company, YPF, as the alter ego of Maxus, to recover all indemnified costs, which will include costs to be incurred at the Site.
In March 2016, the EPA issued a Record of Decision (ROD) specifying remedial actions required for the lower 8.3 miles of the Lower Passaic River. The ROD does not address any potential remedial action for the upper nine miles of the Lower Passaic River or Newark Bay. During the third quarter of 2016, and following Maxus’s bankruptcy filing, Occidental and the EPA entered into an Administrative Order on Consent (AOC) to complete the design of the proposed clean-up plan outlined in the ROD at an estimated cost of $165 million. The EPA announced that it will pursue similar agreements with other potentially responsible parties.
Occidental has accrued a reserve relating to its estimated allocable share of the costs to perform the design and the remediation called for in the AOC and the ROD, as well as for certain other Maxus-indemnified sites. Occidental’s ultimate share of this liability may be higher or lower than the reserved amount, and is subject to final design plans and the resolution of Occidental's allocable share with other potentially responsible parties. Occidental
continues to evaluate the costs to be incurred to comply with the AOC, the ROD and to perform remediation at other Maxus-indemnified sites in light of the Maxus bankruptcy and the share of ultimate liability of other potentially responsible parties.
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 2013 2012 2011
Balance — Beginning of Year $344
 $360
 $366
Remediation expenses and interest accretion 60
 56
 53
Changes from acquisitions/dispositions —
 —
 14
Payments (74) (72) (73)
Balance — End of Year $330
 $344
 $360

Based on current estimates, Occidental expects to expend funds corresponding to approximately half40 percent 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.$1.0 billion.



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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 2013 2012 2011
(in millions) 2016 2015 2014
Operating Expenses            
Oil and Gas $137
 $160
 $158
 $65
 $93
 $103
Chemical 75
 70
 68
 75
 74
 80
Midstream and Marketing 17
 20
 21
 11
 13
 11
 $229
 $250
 $247
 $151
 $180

$194
Capital Expenditures            
Oil and Gas $97
 $122
 $110
 $43
 $122
 $143
Chemical 14
 18
 15
 25
 41
 35
Midstream and Marketing 7
 12
 15
 5
 4
 11
 $118
 $152
 $140
 $73
 $167
 $189
Remediation Expenses            
Corporate $60
 $56
 $52
 $61
 $117
 $79
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 $130$89 million for 2014.2017.

FOREIGN INVESTMENTS
Many of Occidental’s assets are located outside North America. At December 31, 20132016, the carrying value of Occidental’s assets in countries outside North America aggregated approximately $13.7$9.5 billion, or approximately 2022 percent of Occidental’s total assets at that date. Of such assets, approximately $11.9$8.2 billion are located in the Middle East/North AfricaEast and approximately $1.7$1.0 billion are located in Latin America. For the year ended December 31, 2013,2016, net sales outside North America totaled $8.2$3.7 billion, or approximately 3437 percent of total net sales.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The process of preparing financial statements in accordance with generally accepted accounting principles



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

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


32


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 2013,2016, positive revisions of previous estimates provided a net 4of 159 million BOE increasewere primarily positive technical revisions in proved reserves, which amountedAl Hosn Gas and price revisions in Oman due to less than 1 percent of Occidental's total reserves as of December 31, 2013.the PSC impact, partially offset by negative domestic price revisions.
Additionally, Occidental performs impairment tests with respect to its proved properties when productwhenever 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, decline other than temporarily,significant changes in reserve estimates, change significantly,changes in management's plans, or other significant events, occur or management's plans changemanagement 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 respect to these properties in a manner that may impact Occidental's ability to realize the recorded asset amounts. Impairment tests incorporatethose used by market participants. The impairment test incorporates a number of assumptions involving expectations of undiscounted future cash flows which can change significantly over time. These assumptions include estimates of future product prices, which Occidental bases on forward price curves and, when applicable, contractual prices, estimates of risk-adjusted oil and gas reserves and estimates of future expected operating and development costs. Any impairment loss would be calculated as the excess of the asset's net book value over its estimated fair value.It is reasonably possible that prolonged low or further declines in commodity prices, reduced capital spending in response to lower prices or increases in operating costs could result in other additional impairments.
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-percent5 percent increase or decrease in the amount of oil and gas reserves would change the DD&A rate by approximately $0.85$0.60 per barrel, which would



increase or decrease pre-tax income by approximately $240$140 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, 2013, the netNet capitalized costs attributable to unproved properties were $3.6 billion.$1.4 billion and $0.3 billion at December 31, 2016 and 2015, respectively. The unproved amounts are not subject to DD&A until they are classified as proved properties. As exploration and development work progresses, if reserves on these properties are proved, capitalizedCapitalized costs attributable to the properties become subject to DD&A.&A when proved reserves are assigned to the property. If the exploration and development work were to beefforts are unsuccessful, or management decideddecides 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 2013, 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 $0.6 billion for the acreage.
The profitability of certain of Occidental's Middle East/North Africa operations, and in turn its ability to realize its recorded asset values, is dependent upon the success of future development plans or normalization of operations in some locations. Further, the strategic review Occidental is currently undertaking may result in the sale of certain assets, some of which may result in losses. Such losses, if any, will be recorded when a definitive sale decision is made.

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.


33


Occidental's net PP&E for the chemical segment is approximately $2.8$2.4 billion and its depreciation expense for 20142017 is expected to be approximately $325$300 million. The most significant financial statement impact of a decrease in the estimated useful lives of Occidental's chemical plants would be on depreciation expense. For example, a reduction in the remaining useful lives of one year would increase depreciation and reduce pre-tax earnings by approximately $45 million per year.

Midstream, Marketing and Other Assets
Derivatives are carried at fair value and on a net basis when a legal right of offset exists with the same counterparty. Occidental applies hedge accounting when transactions meet specified criteria for cash-flow hedge treatment and management elects and documents such treatment. Otherwise, any fair value gains or losses are recognized in earnings in the current period. For cash-flow hedges, the gain or loss on the effective portion of the derivative is reported as a component of other comprehensive income (OCI) with an offsetting adjustment to the basis of the item being hedged. Realized gains or losses from cash-flow hedges, and any ineffective portion, are recorded as a component of net sales in the consolidated statements of income.operations. 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.operations. There were no fair value hedges as of and during the yearyears ended December 31, 2013.2016, 2015 and 2014.
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:
ØCommodity derivatives – Occidental values exchange-cleared commodity derivatives using closing prices provided by the exchange as of the balance sheet date. These derivatives are classified as Level 1. Over-the-Counter (OTC) bilateral financial commodity contracts, foreign exchange contracts, options and physical commodity forward purchase and sale contracts are generally valued using quotations provided by brokers or industry-standard models that consider various inputs, including quoted forward prices for commodities, time value, volatility factors, credit risk and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument, and can be derived from observable data or are supported by observable prices at which transactions are executed in the marketplace. Occidental generally classifies these measurements as Level 2.
Ø 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.
ØEmbedded commodity derivatives – Occidental values embedded commodity derivatives based on a market approach that considers various assumptions, including quoted forward commodity prices and market yield curves. The assumptions used include inputs that are observable andgenerally 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.



34


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 amountPresently none of discountedthe environmental reserves is insignificant.are recorded on a discounted basis. 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, 2013, 2012 and 2011, 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 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$87 million. If the reserve balance were increased by 10 percent, Occidental would record an additional remediation expense of $33$87 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 Other Contingencies" for additional information.

SIGNIFICANT ACCOUNTING AND DISCLOSURE CHANGES
Listed below are significant recently adopted accountingSee Note 3, Accounting and disclosure changes.

Offsetting Assets and Liabilities
BeginningDisclosure Changes, in the quarter ended March 31, 2013, Occidental adopted new disclosure requirements relatingNotes to its derivativesCondensed Consolidated Financial Statements in accordance with rules issued by the Financial Accounting Standards Board (FASB) in December 2011 and January 2013. These new rules require tabular disclosuresPart II Item 8 of the outstanding derivatives' gross and net fair values, now including those derivatives that are subject to a master netting or similar arrangement and qualify for net presentation, whether or not offset in the consolidated balance sheet.


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Reclassification from Accumulated Other Comprehensive Incomethis Form 10-K.
Beginning in the quarter ended March 31, 2013, Occidental adopted new disclosure requirements for reporting amounts reclassified out of each component of accumulated other comprehensive income into the income statement in accordance with rules issued by the FASB in February 2013.

These new disclosures were not material to Occidental's financial statements.

DERIVATIVE ACTIVITIES AND MARKET RISK
Commodity Price Risk
General
Occidental’s results are sensitive to fluctuations in oil, NGL and natural gas prices. Price changes at current global prices and levels of production affect Occidental’s pre-tax annual income by approximately $150 million for a $1 per barrel change in oil prices and $30 million for a $1 per barrel change in NGL prices. If domestic natural gas prices varied by $0.50 per Mcf, it would have an estimated annual effect on Occidental's pre-tax income of approximately $100 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 2013 average contract prices were: chlorine—$245 per ton; caustic soda—$583 per ton; and PVC—$0.61 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. Additionally, Occidental’s Phibro trading unit engages in trading activities using derivatives for the purpose of generating profits mainly from market price changes of commodities. 

  
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)
 2014 2015 and 2016 2017 and 2018 
2019
and
thereafter
 Total
Prices actively quoted $(13) $(1) $—
 $—
 $(14)
Prices provided by other external sources (5) (23) —
 —
 (28)
Total $(18) $(24) $—
 $—
 $(42)
Note: Includes cash-flow hedges further discussed below.

Cash-Flow Hedges
Occidental entered into financial swap agreements in November 2012 for the sale of a portion of its natural gas production in California. These swap agreements hedge 50 million cubic feet of natural gas per day beginning in January 2013 through March 2014 and qualify as cash-flow hedges. The weighted-average strike price of these swaps is $4.30.
Occidental’s marketing and trading operations store natural gas purchased from third parties at Occidental’s North American leased storage facilities. Derivative instruments are used to fix margins on the future sales of the stored volumes through March 31, 2014. As of December 31, 2013 and 2012, Occidental had approximately 11 billion cubic feet and 20 billion cubic feet of natural gas held in storage, respectively. As of December 31, 2013 and 2012, Occidental had cash-flow hedges for the forecast sale, to be settled by physical delivery, of approximately 13 billion cubic feet and 20 billion cubic feet of this stored natural gas, respectively.


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As of December 31, 2013, the total fair value of cash-flow hedges, which was a net liability of $4 million, was included in the total fair value table in "Fair Value of Marketing and Trading Derivative Contracts" above.

Quantitative Information
Occidental uses value at risk to estimate the potential effects of changes in fair values of commodity-based and foreign currency derivatives and commodity contracts used in marketing and trading activities. This method determines the maximum potential negative short-term change in fair value with at least a 95-percent level of confidence. Additionally, Occidental uses trading limits, including, among others, limits on total notional trade value, and maintains liquid positions as a result of which market risk typically can be neutralized on short notice. As a result of these controls, Occidental has determined that the market risk of the marketing and trading activities is not reasonably likely to have a material adverse effect on 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, 2013, 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)
2014 $—
 $—
 $—
2015 —
 —
 —
2016 1,450
 —
 1,450
2017 1,250
 —
 1,250
2018 500
 —
 500
Thereafter 3,696
 68
 3,764
Total $6,896
 $68
 $6,964
Weighted-average interest rate 3.16% 0.04% 3.13%
Fair Value $7,062
 $68
 $7,130
(a)Excludes unamortized debt discounts of $25 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 substantial portion of Occidental’s derivative transaction volume is executed through exchange-traded contracts, which are subject to nominal credit risk as a significant portion of these transactions is settled on a daily margin basis with select clearinghouses and brokers. Occidental executes the rest of its derivative transactions in the OTC market. Occidental is subject to counterparty credit risk to the extent the counterparty to the derivatives is unable to meet its settlement commitments. Occidental manages this credit risk by selecting counterparties that it believes to be financially strong, by spreading the credit risk among many such counterparties, by entering into master netting arrangements with the counterparties and by requiring collateral, as appropriate. Occidental actively monitors the creditworthiness of each counterparty and records valuation adjustments to reflect counterparty risk, if necessary.
Certain of Occidental's OTC derivative instruments contain credit-risk-contingent features, primarily tied to credit ratings for Occidental or its counterparties, which may affect the amount of collateral that each would need to post. As of December 31, 2013 and 2012, Occidental had a net liability of $8 million and $34 million, respectively, which are net of collateral posted of $23 million and $64 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, 2013 and 2012.
As of December 31, 2013, the substantial majority of the credit exposures was with investment grade counterparties. Occidental believes its exposure to credit-related losses at December 31, 2013 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, 2013, 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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SAFE HARBOR DISCUSSION REGARDING OUTLOOK AND OTHER FORWARD-LOOKING DATA
Portions of this report, including Items 1 and 2, (including the information appearing under the captions “Oil"Business and Gas Operations - Competition,” “Chemical Operations - Competition,” and Midstream and Marketing Operations - Competition”),Properties," Item 3, "Legal Proceedings," and ItemsItem 7 and 7A (including "Management's Discussion and Analysis of Financial Condition and Results of Operations," including the information under the sub-captions "Strategy," "Oil and Gas Segment  -Business Review," “Proved Reserves”Item 7A, "Quantitative and "- Industry Outlook," "Chemical Segment - Industry Outlook," "Midstream, Marketing and Other Segment - Business Review, Gas Processing Plants and CO2 Fields and Facilities" and "- Business Review, Pipeline Transportation," "- Industry Outlook," "Taxes," "Liquidity and Capital Resources," “Contractual Obligations - Delivery Commitments,” "Lawsuits, Claims and Other Contingencies," "Environmental Liabilities and Expenditures," "Critical Accounting Policies and Estimates," and "Derivative Activities andQualitative Disclosures About Market Risk"),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,
"goal," "target," "objective," "likely" or similar expressions that convey the prospective nature of events or outcomes generally indicate forward-looking statements. You should not place undue reliance on these forward-looking statements, which speak only as of the date of this report. Unless legally required, Occidental does not undertake any obligation to update any forward-looking statements as a result of new information, future events or otherwise. Factors that may cause Occidental’s results of operations and financial position to differ from expectations include items notedthe factors discussed in Item 1A, "Risk Factors" and elsewhere,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 alsonatural gas prices. Price changes at current global prices and levels of production affect Occidental’s pre-tax annual income by approximately $120 million for a $1 per barrel change in oil prices and $30 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 needimpact 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. Marketing results are sensitive to price changes of oil, natural gas and, to a lesser degree, other commodities. These sensitivities are additionally dependent on marketing volumes and cannot be predicted reliably.
Occidental’s results are also sensitive to fluctuations in chemical prices. A variation in chlorine and caustic soda prices of $10 per ton would have a pre-tax annual effect on income of approximately $10 million and $30 million, respectively. A variation in PVC prices of $0.01 per lb. would have a pre-tax annual effect on income of approximately $30 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 or Townsend, 2016 average contract prices were: chlorine—$298 per ton; caustic soda—$645 per ton; and PVC—$0.38 per lb.
Occidental uses derivative instruments, including a combination of short-term futures, forwards, options and swaps, to obtain the average prices for final Boardthe relevant production month and to improve realized prices for oil and gas.
Risk Management
Occidental conducts its risk management activities for marketing and trading under the controls and governance of Directors approvalits risk control policies. The controls under these policies are implemented and enforced by a risk management group which monitors risk by providing an independent and separate evaluation and check. Members of the California separation. risk management group report to the Corporate Vice President and Treasurer. 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, reporting to senior management of various risk measures and a number of other policy and procedural controls.
Fair Value of Marketing Derivative Contracts
Occidental postscarries derivative contracts it enters into in connection with its marketing activities at fair value. Fair values for these contracts are derived from Level 1 and Level 2 sources. The fair values in future maturity periods are insignificant.
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)
 2017 2018 and 2019 2020 and 2021 Total
Prices actively quoted $(6) $—
 $—
 $(6)
Prices provided by other external sources —
 (1) —
 (1)
Total $(6) $(1) $—
 $(7)
Cash-Flow Hedges
Occidental’s marketing operations, from time to time, store natural gas purchased from third parties at Occidental’s North American leased storage facilities. At December 31, 2016, Occidental had approximately 7 Bcf of natural gas held in storage, and had cash-flow hedges for the forecast sale, to be settled by physical delivery, of approximately 7 Bcf of stored natural gas. As of December 31, 2015, Occidental had approximately 13 Bcf of natural gas held in storage, and had cash-flow hedges for the forecast sale, to be settled by physical delivery, of approximately 14 Bcf of stored natural gas.
Quantitative Information
Occidental uses value at risk to estimate the potential effects of changes in fair values of commodity contracts used in trading activities. This measure determines the maximum potential negative one day change in fair value with a 95 percent level of confidence. Additionally, Occidental uses complementary trading limits including position and tenor limits and maintains liquid positions as a result of which market risk typically can be neutralized or provides linksmitigated on short notice. As a result of these controls, Occidental has determined that market risk of its trading activities is not reasonably likely to important informationhave a material adverse effect on its website at www.oxy.com.performance.  
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, 2016, variable-rate debt constituted approximately 1 percent of Occidental's total debt.
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, 2016, the fair value of foreign currency derivatives used in the marketing operations was immaterial. The effect of exchange rates on transactions in foreign currencies is included in periodic income.

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)
2017 $—
 $—
 —
2018 500
 —
 500
2019 116
 —
 116
2020 —
 —
 —
2021 1,249
 —
 1,249
Thereafter 7,974
 68
 8,042
Total $9,839
 $68
 $9,907
Weighted-average interest rate 3.67% 0.90% 3.65%
Fair Value $10,001
 $68
 $10,069
(a)Excludes unamortized debt discounts of $36 million and debt issuance cost of $52 million.

Credit Risk
The majority of Occidental's counterparty credit risk is related to the physical delivery of energy commodities to its customers and their inability to meet their settlement commitments. Occidental manages credit risk by selecting counterparties that it believes to be financially strong, by entering into master netting arrangements with counterparties and by requiring collateral or other credit risk mitigants, as appropriate. Occidental actively evaluates the creditworthiness of its counterparties, assigns appropriate credit limits, and monitors credit exposures against those assigned limits. Occidental also enters into future contracts through regulated exchanges with select clearinghouses and brokers, which are subject to minimal credit risk as a significant portion of these transactions settle on a daily margin basis.
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. 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, 2016 and 2015.
As of December 31, 2016, the substantial majority of the credit exposures were with investment grade counterparties. Occidental believes its exposure to credit-related losses at December 31, 2016 was not material and losses associated with credit risk have been insignificant for all years presented.


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ITEM 8    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
MANAGEMENT'S ANNUAL ASSESSMENT OF AND REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The management of Occidental Petroleum Corporation and 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, 2013, based on the criteria for effective internal control over financial reporting described in Internal Control — Integrated Framework issued in 1992 by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this assessment, management believes that, as of December 31, 2013, Occidental’s system of internal control over financial reporting is effective.
Occidental’s independent auditors, KPMG LLP, have issued an audit report on Occidental’s internal control over financial reporting.


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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM ON CONSOLIDATED FINANCIAL STATEMENTS

To theThe Board of Directors and Stockholders
Occidental Petroleum Corporation:

We have audited the accompanying consolidated balance sheets of Occidental Petroleum Corporation and subsidiaries (the Company) as of December 31, 20132016 and 2012,2015, and the related consolidated statements of income,operations, comprehensive income, stockholders’ equity, and cash flows for each of the years in the three-yearthree‑year period ended December 31, 2013.2016. 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, 20132016 and 2012,2015, and the results of their operations and their cash flows for each of the years in the three-yearthree‑year period ended December 31, 2013,2016, 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'Corporation’s internal control over financial reporting as of December 31, 2013,2016, based on criteria established in Internal Control - Integrated Framework (2013)issued in 1992 by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 3, 2014February 23, 2017 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/ KPMG LLP
Los Angeles, CaliforniaHouston, Texas
March 3, 2014February 23, 2017


40



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM ON INTERNAL CONTROL OVER FINANCIAL REPORTING

To theThe Board of Directors and Stockholders
Occidental Petroleum Corporation:

We have audited Occidental Petroleum Corporation and subsidiaries' (the Company)Corporation’s internal control over financial reporting as of December 31, 2013,2016, based on criteria established in Internal Control - Integrated Framework (2013)issued in 1992 by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company'sOccidental 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 Overover 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'scompany’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'scompany’s internal control over financial reporting includes those policies and procedures that: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, 2013,2016, based on criteria established in Internal Control - Integrated Framework (2013)issued in 1992 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, 20132016 and 2012,2015, and the related consolidatedstatements of income,operations, comprehensive income, stockholders’ equity, and cash flows for each of the years in the three-yearthree‑year period ended December 31, 2013,2016, and our report dated March 3, 2014February 23, 2017 expressed an unqualified opinion on those consolidated financial statements.


Los Angeles, California/s/ KPMG LLP
March 3, 2014Houston, Texas
February 23, 2017

41



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

Assets at December 31, 2013 2012 2016 2015
CURRENT ASSETS        
Cash and cash equivalents $3,393
 $1,592
 $2,233
 $3,201
Trade receivables, net of reserves of $17 in 2013 and $16 in 2012 5,674
 4,916
Restricted cash —
 1,193
Trade receivables, net of reserves of $16 in 2016 and $17 in 2015 3,989
 2,970
Inventories 1,200
 1,344
 866
 986
Assets held for sale —
 141
Other current assets 1,056
 1,640
 1,340
 911
Total current assets 11,323
 9,492
 8,428
 9,402
        
INVESTMENTS IN UNCONSOLIDATED ENTITIES 1,459
 1,894
INVESTMENTS    
Investment in unconsolidated entities 1,401
 1,267
Available for sale investment —
 167
Total investments 1,401
 1,434
        
PROPERTY, PLANT AND EQUIPMENT        
Oil and gas segment 72,367
 65,417
 54,673
 55,025
Chemical segment 6,446
 6,054
 6,930
 6,717
Midstream, marketing and other segment 8,684
 7,191
Midstream and marketing 9,216
 8,899
Corporate 1,555
 1,434
 474
 417
 89,052
 80,096
 71,293
 71,058
Accumulated depreciation, depletion and amortization (33,231) (28,032) (38,956) (39,419)
 55,821
 52,064
 32,337
 31,639
        
LONG-TERM RECEIVABLES AND OTHER ASSETS, NET 840
 760
 943
 934
        
TOTAL ASSETS $69,443
 $64,210
 $43,109
 $43,409
 
The accompanying notes are an integral part of these consolidated financial statements.


42



Consolidated Balance Sheets
Occidental Petroleum Corporation
and Subsidiaries
In(in millions, except share and per-share amountsamounts)

Liabilities and Stockholders’ Equity at December 31, 2013 2012 2016 2015
CURRENT LIABILITIES        
Current maturities of long-term debt $—
 $600
 $—
 $1,450
Accounts payable 5,520
 4,708
 3,926
 3,069
Accrued liabilities 2,556
 1,966
 2,436
 2,213
Domestic and foreign income taxes 358
 16
Liabilities of assets held for sale —
 110
Total current liabilities 8,434
 7,290
 6,362
 6,842
        
LONG-TERM DEBT, NET 6,939
 7,023
 9,819
 6,855
        
DEFERRED CREDITS AND OTHER LIABILITIES        
Deferred domestic and foreign income taxes 7,197
 6,039
 1,132
 1,323
Other 3,501
 3,810
 4,299
 4,039
 10,698
 9,849
 5,431
 5,362
CONTINGENT LIABILITIES AND COMMITMENTS    
    
STOCKHOLDERS' EQUITY        
Common stock, $0.20 per share par value, authorized shares: 1.1 billion, outstanding shares:
2013 — 889,919,058 and 2012 — 888,801,436
 178
 178
Treasury stock: 2013 — 93,928,179 shares and 2012 — 83,287,187 shares (6,095) (5,091)
Common stock, $0.20 per share par value, authorized shares: 1.1 billion, issued shares:
2016 — 892,214,604 and 2015 — 891,360,091		 178
 178
Treasury stock: 2016 — 127,977,306 shares and 2015 — 127,681,335 shares (9,143) (9,121)
Additional paid-in capital 7,515
 7,441
 7,747
 7,640
Retained earnings 41,831
 37,990
 22,981
 25,960
Accumulated other comprehensive loss (303) (502) (266) (307)
Total equity attributable to common stock 43,126
 40,016
Noncontrolling interest 246
 32
Total equity 43,372
 40,048
Total stockholders' equity 21,497
 24,350
        
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $69,443
 $64,210
 $43,109
 $43,409
 
The accompanying notes are an integral part of these consolidated financial statements.


43



Consolidated Statements of IncomeOperations
Occidental Petroleum Corporation
and Subsidiaries
In(in millions, except per-share amountsamounts)

For the years ended December 31, 2013 2012 2011 2016 2015 2014
REVENUES AND OTHER INCOME            
Net sales $24,455
 $24,172
 $23,939
 $10,090
 $12,480
 $19,312
Interest, dividends and other income 106
 81
 180
 106
 118
 130
Gain on sale of equity investments 1,175
 —
 —
Gain on sale of equity investments and other assets 202
 101
 2,505
 25,736
 24,253
 24,119
 10,398
 12,699
 21,947
            
COSTS AND OTHER DEDUCTIONS  
      
    
Cost of sales (excludes depreciation, depletion and amortization of $5,341 in 2013, $4,504 in 2012 and $3,584 in 2011) 7,562
 7,844
 7,385
Cost of sales (excludes depreciation, depletion, and amortization of $4,266 in 2016, $4,540 in 2015, and $4,257 in 2014) 5,189
 5,804
 6,803
Selling, general and administrative and other operating expenses 1,801
 1,602
 1,523
 1,330
 1,270
 1,503
Depreciation, depletion and amortization 5,347
 4,511
 3,591
 4,268
 4,544
 4,261
Asset impairments and related items 621
 1,751
 —
 825
 10,239
 7,379
Taxes other than on income 749
 680
 605
 277
 343
 550
Exploration expense 256
 345
 258
 62
 36
 150
Interest and debt expense, net 118
 130
 298
 292
 147
 77
 16,454
 16,863
 13,660
 12,243
 22,383
 20,723
INCOME BEFORE INCOME TAXES AND OTHER ITEMS 9,282
 7,390
 10,459
Provision for domestic and foreign income taxes (3,755) (3,118) (4,201)
INCOME (LOSS) BEFORE INCOME TAXES AND OTHER ITEMS (1,845) (9,684) 1,224
(Provision for) benefit from domestic and foreign income taxes 662
 1,330
 (1,685)
Income from equity investments 395
 363
 382
 181
 208
 331
            
INCOME FROM CONTINUING OPERATIONS 5,922
 4,635
 6,640
INCOME (LOSS) FROM CONTINUING OPERATIONS (1,002) (8,146) (130)
Income from discontinued operations 428
 317
 760
      
NET INCOME (LOSS) $(574) $(7,829) $630
Less: Net income attributable to noncontrolling interest —
 —
 (14)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK $(574) $(7,829) $616
      
BASIC EARNINGS (LOSS) PER COMMON SHARE (attributable to common stock)      
Income (loss) from continuing operations $(1.31) $(10.64) $(0.18)
Discontinued operations, net (19) (37) 131
 0.56
 0.41
 0.97
BASIC EARNINGS (LOSS) PER COMMON SHARE $(0.75) $(10.23) $0.79
            
NET INCOME $5,903
 $4,598
 $6,771
      
BASIC EARNINGS PER COMMON SHARE      
Income from continuing operations $7.35
 $5.72
 $8.16
DILUTED EARNINGS (LOSS) PER COMMON SHARE (attributable to common stock)      
Income (loss) from continuing operations $(1.31) $(10.64) $(0.18)
Discontinued operations, net (0.02) (0.05) 0.16
 0.56
 0.41
 0.97
BASIC EARNINGS PER COMMON SHARE $7.33
 $5.67
 $8.32
      
DILUTED EARNINGS PER COMMON SHARE      
Income from continuing operations $7.34
 $5.71
 $8.16
Discontinued operations, net (0.02) (0.04) 0.16
DILUTED EARNINGS PER COMMON SHARE $7.32
 $5.67
 $8.32
DILUTED EARNINGS (LOSS) PER COMMON SHARE $(0.75) $(10.23) $0.79
DIVIDENDS PER COMMON SHARE $2.56
 $2.16
 $1.84
 $3.02
 $2.97
 $2.88
The accompanying notes are an integral part of these consolidated financial statements.            

44



Consolidated Statements of Comprehensive Income
Occidental Petroleum Corporation
and Subsidiaries
In millions(in millions)
 
For the years ended December 31, 2013 2012 2011
Net income $5,903
 $4,598
 $6,771
Other comprehensive income (loss) items:      
Foreign currency translation gains (losses) 2
 (25) (11)
Realized foreign currency translation losses 28
 —
 —
Unrealized (losses) gains on derivatives (a)
 (3) 16
 14
Pension and postretirement gains (losses) (b)
 176
 14
 (60)
Reclassification to income of realized (gains) losses on derivatives (c)
 (4) (24) 98
Other comprehensive income (loss), net of tax (d)
 199
 (19) 41
Comprehensive income $6,102
 $4,579
 $6,812
For the years ended December 31, 2016 2015 2014
Net income (loss) attributable to common stock $(574) $(7,829) $616
Other comprehensive income (loss) items:      
Foreign currency translation (losses) gains —
 (2) (2)
Unrealized gains (losses) on derivatives (a)
 (14) 3
 (5)
Pension and postretirement gains (losses) (b)
 47
 48
 (77)
Distribution of California Resources to shareholders (c)
 —
 —
 22
Reclassification to income of realized losses (gains) on derivatives (d)
 8
 1
 8
Other comprehensive income (loss), net of tax (e)
 41
 50
 (54)
Comprehensive income (loss) $(533) $(7,779) $562
(a)
Net of tax of $2, $(9)$8, $(2) and $(7)$3 in 2013, 20122016, 2015 and 2011,2014, respectively.
The 2015 amount includes a lower of cost or market inventory adjustment for hedged natural gas of $(2).
(b)
Net of tax of $(101)$(26), $(8)$(27) and $34$44 in 2013, 20122016, 2015 and 2011,2014, respectively. See Note 13, Retirement and Postretirement Benefit Plans, for additional information.
(c)
Net of tax of $2, $14 and $(56)$(14) in 2013, 2012 and 2011, respectively.
2014. Employees of California Resources no longer participate in Occidental benefit plans as of the separation date, see Note 17, Spin-off of California Resources.
(d)
Net of tax of $(4), $(1) and $(5) in 2016, 2015 and 2014, respectively.
(e)There were no other comprehensive income (loss) items related to noncontrolling interests in 2013, 20122016, 2015 and 2011.
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, 2010 $177
 $(4,228) $7,191
 $29,868
 $(524) $—
 $32,484
Net income —
 —
 —
 6,771
 —
 —
 6,771
Other comprehensive income, net of tax —
 —
 —
 —
 41
 —
 41
Dividends on common stock —
 —
 —
 (1,497) —
 —
 (1,497)
Issuance of common stock and other, net —
 —
 95
 —
 —
 —
 95
Purchases of treasury stock —
 (274) —
 —
 —
 —
 (274)
Balance, December 31, 2011 $177
 $(4,502) $7,286
 $35,142
 $(483) $—
 $37,620
Net income —
 —
 —
 4,598
 —
 —
 4,598
Other comprehensive loss, net of tax —
 —
 —
 —
 (19) —
 (19)
Dividends on common stock —
 —
 —
 (1,750) —
 —
 (1,750)
Issuance of common stock and other, net 1
 —
 155
 —
 —
 —
 156
Noncontrolling interest contributions —
 —
 —
 —
 —
 32
(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
(a)Reflects contributions from the noncontrolling interest in a pipeline company.2014.

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

45


Consolidated Statements of Stockholders' Equity
Occidental Petroleum Corporation
and Subsidiaries
(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, 2013 $178
 $(6,095) $7,515
 $41,831
 $(303) $246
 $43,372
Net income —
 —
 —
 616
 —
 —
 616
Other comprehensive loss, 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 and other —
 —
 —
 —
 —
 (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
Net loss —
 —
 —
 (7,829) —
 —
 (7,829)
Other comprehensive income, net of tax —
 —
 —
 —
 50
 —
 50
Dividends on common stock —
 —
 —
 (2,278) —
 —
 (2,278)
Issuance of common stock and other, net —
 —
 41
 —
 —
 —
 41
Purchases of treasury stock —
 (593) —
 —
 —
 —
 (593)
Balance, December 31, 2015 $178
 $(9,121) $7,640
 $25,960
 $(307) $—
 $24,350
Net loss —
 —
 —
 (574) —
 —
 (574)
Other comprehensive income, net of tax —
 —
 —
 —
 41
 —
 41
Dividends on common stock —
 —
 —
 (2,405) —
 —
 (2,405)
Issuance of common stock and other, net —
 —
 107
 —
 —
 —
 107
Purchases of treasury stock —
 (22) —
 —
 —
 —
 (22)
Balance, December 31, 2016 $178
 $(9,143) $7,747
 $22,981
 $(266) $—
 $21,497
(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.


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

For the years ended December 31, 2013 2012 2011 2016 2015 2014
CASH FLOW FROM OPERATING ACTIVITIES            
Net income $5,903
 $4,598
 $6,771
Adjustments to reconcile net income to net cash provided by operating activities:      
Discontinued operations, net 19
 37
 (131)
Net income (loss) $(574) $(7,829) $630
Adjustments to reconcile net income (loss) to net cash provided by operating activities:      
Income from discontinued operations (428) (317) (760)
Depreciation, depletion and amortization of assets 5,347
 4,511
 3,591
 4,268
 4,544
 4,261
Deferred income tax provision 1,187
 1,128
 1,436
Deferred income tax benefit (517) (1,372) (1,178)
Other noncash charges to income 299
 195
 190
 121
 159
 101
Asset impairments and related items 621
 1,751
 —
 665
 9,684
 7,379
Gain on sale of equity investments (1,175) —
 —
Gain on sale of equity investments and other assets (202) (101) (2,505)
Undistributed earnings from equity investments (3) (30) (33) 3
 6
 38
Dry hole expenses 142
 279
 160
 33
 10
 99
Changes in operating assets and liabilities:            
(Increase) decrease in receivables (755) 472
 (360)
Decrease (increase) in receivables (1,091) 1,431
 1,413
Decrease (increase) in inventories 87
 (265) (50) 17
 (24) (112)
Decrease in other current assets 60
 127
 95
 65
 33
 89
Increase (decrease) in accounts payable and accrued liabilities 500
 (1,086) 657
Increase (decrease) in current domestic and foreign income taxes 369
 1
 (174)
(Decrease) increase in accounts payable and accrued liabilities 603
 (1,989) (530)
(Decrease) increase in current domestic and foreign income taxes 17
 (331) (54)
Other operating, net 382
 (370) 154
 (461) (650) —
Operating cash flow from continuing operations 12,983
 11,348
 12,306
 2,519
 3,254
 8,871
Operating cash flow from discontinued operations, net of taxes (56) (36) (25) 864
 97
 2,197
Net cash provided by operating activities 12,927
 11,312
 12,281
 3,383
 3,351
 11,068
            
CASH FLOW FROM INVESTING ACTIVITIES            
Capital expenditures (9,037) (10,226) (7,518) (2,717) (5,272) (8,930)
Change in capital accrual (114) (592) 542
Payments for purchases of assets and businesses (643) (2,490) (4,909) (2,044) (109) (1,687)
Sales of equity investments and assets, net 1,619
 4
 50
 302
 819
 4,177
Other, net (132) 57
 (96) (169) (269) (346)
Investing cash flow from continuing operations (8,193) (12,655) (12,473) (4,742) (5,423) (6,244)
Investing cash flow from discontinued operations —
 —
 2,570
 —
 —
 (2,226)
Net cash used by investing activities (8,193) (12,655) (9,903) (4,742) (5,423) (8,470)
            
CASH FLOW FROM FINANCING ACTIVITIES            
Change in restricted cash 1,193
 2,826
 (4,019)
Special cash distributions from California Resources —
 —
 6,100
Proceeds from long-term debt 4,203
 1,478
 —
Payments of long-term debt (690) —
 (1,523) (2,710) —
 (107)
Proceeds from long-term debt —
 1,736
 2,111
Proceeds from issuance of common stock 30
 85
 50
 36
 37
 33
Purchases of treasury stock (943) (583) (274) (22) (593) (2,500)
Contributions from (distributions to) noncontrolling interest 214
 32
 (121)
Contributions from noncontrolling interest —
 —
 375
Cash dividends paid (1,553) (2,128) (1,436) (2,309) (2,264) (2,210)
Other, net 9
 12
 18
 —
 —
 2
Net cash used by financing activities (2,933) (846) (1,175)
Financing cash flow from continuing operations 391
 1,484
 (2,326)
Financing cash flow from discontinued operations —
 —
 124
Net cash provided (used) by financing activities 391
 1,484
 (2,202)
      
Increase (decrease) in cash and cash equivalents 1,801
 (2,189) 1,203
 (968) (588) 396
Cash and cash equivalents — beginning of year 1,592
 3,781
 2,578
 3,201
 3,789
 3,393
Cash and cash equivalents — end of year $3,393
 $1,592
 $3,781
 $2,233
 $3,201
 $3,789

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

46



Notes to Consolidated Financial Statements
Occidental Petroleum Corporation
and Subsidiaries
 

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 the oil and gas, chemical and midstream, marketing and other (midstream and marketing)three segments. The oil and gas segment explores for, develops and produces oil and condensate, natural gas liquids (NGL)(NGLs) and natural gas. The chemical segment (OxyChem) mainly manufactures and markets basic chemicals and vinyls. The midstream and marketing segment gathers, processes, transports, stores, purchases and markets oil, condensate, NGLs, natural gas, carbon dioxide (CO2) and power. It also trades around its assets, including transportation and storage capacity, and trades oil, NGLs, gas and other commodities.capacity. 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 20132016 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 year ended December 31, 2014. 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.

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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 $13.7$9.5 billion as of December 31, 2013,2016, and net sales of approximately $8.2$3.7 billion for the year ended December 31, 2013,2016, relating to Occidental’s operations in countries outside North America. Occidental operates some of its oil and gas business in countries that occasionally have experienced political instability, nationalizations, 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 $2.9$2.0 billion and $1.0$2.9 billion at December 31, 20132016 and 20122015, respectively.

RESTRICTED CASH
Restricted cash is the result of the separation of California Resources in 2014. As of December 31, 2015, there was $1.2 billion of cash restricted for the payment of dividends, payment of debt or share repurchases. In 2016, Occidental utilized the remaining restricted cash balance to retire debt and pay dividends.
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, NGLNGLs 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 2013 2012 2011
in millions 2016 2015 2014
Balance — Beginning of Year $124
 $189
 $77
 $76
 $141
 $140
Additions to capitalized exploratory well costs pending the determination of proved reserves 337
 400
 333
 29
 88
 462
Reclassifications to property, plant and equipment based on the determination of proved reserves (271) (389) (201) (28) (78) (423)
Spin-off of California Resources —
 —
 (17)
Capitalized exploratory well costs charged to expense (50) (76) (20) (21) (75) (21)
Balance — End of Year $140
 $124
 $189
 $56
 $76
 $141

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.

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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.
Additionally, Occidental performs impairment tests with respect to its proved properties when productwhenever 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, decline other than temporarily,significant changes in reserve estimates, change significantly,changes in management's plans, or other significant events, occur or management's plans changemanagement 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 respect to these properties in a manner that may impact Occidental's ability to realize the recorded asset amounts. Impairment tests incorporatethose used by market participants. The impairment test incorporates a number of assumptions involving expectations of undiscounted future cash flows which can change significantly over time. These assumptions include estimates of future product prices, which Occidental bases on forward price curves and, when applicable, contractual prices, estimates of risk-adjusted oil and gas reserves and estimates of future expected operating and development costs. Any impairment loss would be calculated as the excessSee Note 15 and below for further discussion of the asset's net book value over its estimated fair value.asset impairments.
A portion of the carrying value of Occidental’s oil and gas properties is attributable to unproved properties. At December 31, 2013, the netNet capitalized costs attributable to unproved properties were $3.6 billion.$1.4 billion and $0.3 billion at December 31, 2016 and 2015, respectively. The unproved amounts are not subject to DD&A until they are classified as proved properties. As exploration and development work progresses, if reserves on these properties are proved, capitalizedCapitalized costs attributable to the properties become subject to DD&A.&A when proved reserves are assigned to the property. If the exploration and development work were to beefforts are unsuccessful, or management decideddecides 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.

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 50fifty 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.
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.

IMPAIRMENTS AND RELATED ITEMS
In 2016, Occidental recorded net impairment and related charges of $61 million related to the sale of Libya and exit from Iraq and the termination of crude oil supply contracts at a cost of $160 million. The corporate amount included an allowance for doubtful accounts.
In 2015, Occidental recorded impairment and related charges on oil and gas assets due to the decline in oil and gas prices, the decision to sell or exit non-core assets and changes in development plans for its non-producing assets. In November 2015, Occidental sold its Williston Basin assets in North Dakota and in December 2015, Occidental entered into an agreement to sell its Piceance Basin operations in Colorado. In Iraq, Occidental issued a notice of withdrawal and reassigned its interest in the Zubair Field in accordance with the contract terms. In Bahrain, Occidental issued a notice of withdrawal, reassigning its interest, and completed the exit in 2016. In Yemen, Occidental’s non-operated interest in Block 10 East Shabwa Field expired in December 2015, and in February 2016, Occidental sold its interests in Block S-1, An Nagyah Field.
In 2015, the midstream and marketing segment recorded an impairment charge for the Century gas processing plant as a result of SandRidge's inability to provide volumes to the plant and meet its contractual obligations to deliver CO2.
In 2014, Occidental recorded impairment and related charges mainly for Williston, Bahrain, the Joslyn oil sands project and other non-core domestic gas properties due to declining prices and changes in development plans.
For the years ended December 31, (in millions) 2016 2015 2014
OIL AND GAS      
United States      
Impairments and related charges of exiting operations $(44) $1,862
(a) 
$3,253
Impairments related to decline in commodity prices and changes in future development plans 15
 1,428
 1,381
Rig termination charges —
 192
 —
Other asset impairment related charges 5
 204
 119
       
Latin America      
Impairments related to decline in commodity prices 9
 559
 57
       
Middle East and North Africa      
Impairments of exiting operations 61
 1,658
 918
Impairments related to decline in commodity prices —
 2,833
 91
       
CHEMICAL      
Impairments of assets —
 121
 149
       
MIDSTREAM AND MARKETING      
Century gas processing plant —
 814
 —
Other asset impairment related charges 160
 216
 40
       
CORPORATE      
Other-than-temporary impairment of investment in California Resources 78
 227
 553
Joslyn impairment —
 —
 805
Severance, spin-off and allowance for doubtful accounts 541
 125
 13
       
  $825
 $10,239
 $7,379
(a)A portion of the 2015 charges are reported in the Midstream and Marketing segment.


It is reasonably possible that prolonged or further declines in commodity prices, reduced capital spending in response to lower prices or increases in operating costs could result in other additional impairments.

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.

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Fair Values - Recurring
Occidental primarily applies the market approach for recurring fair value measurements, maximizes its use of observable inputs and minimizes its use of unobservable inputs. Occidental utilizes the mid-point 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:
ØCommodity derivatives – Occidental values exchange-cleared commodity derivatives using closing prices provided by the exchange as of the balance sheet date. These derivatives are classified as Level 1.
ØOver-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 classifies these measurements as Level 2.
ØEmbedded commodity derivatives – Occidental values embedded commodity derivatives based on a market approach that considers various assumptions, including quoted forward commodity prices and market yield curves. The assumptions used include inputs that are observable andgenerally 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 $459$341 million and $385$188 million at December 31, 20132016 and 20122015, 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 amountPresently none of discountedthe environmental reserves is insignificant.are recorded on a discounted basis. 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, 2013, 2012 and 2011, Occidental did not have any accruals for reimbursements or recoveries.
Many factors could affect Occidental’sOccidental'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.

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

ASSET RETIREMENT OBLIGATIONS
Occidental recognizes the fair value of asset retirement obligations in the period in which a determination is made that a legal obligation exists to dismantle an asset and reclaim or remediate the property at the end of its useful life and the cost of the obligation can be reasonably estimated. The liability amounts are based on future retirement cost estimates and incorporate many assumptions such as time to abandonment, technological changes, future inflation rates and the risk-adjusted discount rate. When the liability is initially recorded, Occidental capitalizes the cost by increasing the related PP&E balances. If the estimated future cost of the asset retirement obligation changes, Occidental records an adjustment to both the asset retirement obligation and PP&E. Over time, the liability is increased and expense is recognized for accretion, and the capitalized cost is depreciated over the useful life of the asset.
At a certain number of its facilities, Occidental has identified conditional asset retirement obligations that are related mainly to plant decommissioning. Occidental 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 $1,283 million and $1,212 million$1.2 billion is included in deferred credits and other liabilities - other, with the remaining current portion in accrued liabilities at both December 31, 20132016 and 20122015, respectively..
For the years ended December 31, (in millions) 2013 2012 2016 2015
Beginning balance $1,266
 $1,089
 $1,124
 $1,091
Liabilities incurred – capitalized to PP&E 101
 86
 46
 46
Liabilities settled and paid (72) (58) (38) (35)
Accretion expense 68
 61
 59
 54
Acquisitions, dispositions and other – changes in PP&E (10) 50
 11
 (209)
Revisions to estimated cash flows – changes in PP&E (21) 38
 167
 177
Ending balance $1,332
 $1,266
 $1,369
 $1,124

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.operations. 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.operations. There were no fair value hedges as of and during the years ended December 31, 20132016, 20122015 and 20112014.
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 forecastforecasted transaction is no longer deemed probable.


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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.stock and the estimated payout at the grant date. For cash- and stock-settled total shareholder return incentives (TSRIs), compensation value is initially measured on the grant date using estimated payout levels derived from thea 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 cash-settled portion of the TSRIdividends accrued on unvested awards and related dividends is adjusted quarterly for any changes in stock price and the number of share equivalents expected to be paid based on the relevant performance criteria. For RSUs, compensation expense for the cash-settled portion of the awards is adjusted for changes in the value of the underlying stock on a quarterly basis.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 $1.8$0.3 billion,, $2.4 $1.0 billion and $2.9 billion during the years ended December 31, 2013, 20122016, 2015 and 2011,2014, respectively. Occidental also paid production, property and other taxes of approximately $792$343 million, $694$445 million and $635$610 million during the years ended December 31, 2013, 20122016, 2015 and 2011,2014, respectively, substantially all of which was in the United States. Interest paid totaled approximately $238$312 million,, $190 $246 million and $315$219 million, net of capitalized interest of $64 million, $138 million and $180 million, for the years 2013, 20122016, 2015 and 2011,2014, respectively. The 2011 interest paid included $154 million of debt extinguishment premiums.

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


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NOTE 2ACQUISITIONS, DISPOSITIONS AND OTHER TRANSACTIONS

SUBSEQUENT EVENTS2016
In 2016, Occidental completed its exit of non-core operations in Bahrain, Iraq, Libya and Yemen.
In November 2016, Occidental issued $1.5 billion of senior notes, comprised of $750 million of 3.0-percent senior notes due 2027 and $750 million of 4.1-percent senior notes due 2047. Occidental received net proceeds of $1.49 billion. Interest on the senior notes is payable semi-annually in arrears in February and August each year for each series of senior notes beginning August 15, 2017. Occidental used the proceeds for general corporate purposes.
In October 2016, Occidental acquired producing and non-producing leasehold acreage in the Permian Basin. This acquisition includes 35,000 net acres in Reeves and Pecos counties, Texas in the Southern Delaware Basin, in areas where Occidental currently operates or has working interests. Separately, Occidental also acquired working interests in several producing oil and gas CO2 floods and related EOR infrastructure, increasing Occidental's ownership in several properties where it is currently the operator or an existing working interest partner. The total purchase price for these transactions was approximately $2.0 billion which was allocated between unproved and proved property.
In September 2016, Occidental completed the sale of its South Texas Eagle Ford non-operated properties for $63 million resulting in a pre-tax gain of $59 million.
In August 2016, Occidental terminated crude oil supply contracts at a cost of $160 million.
In the second quarter of 2016, Occidental received $330 million as final payment from the settlement with the Republic of Ecuador. In January 2016, Occidental reached an understanding on the terms of payment for the approximate $1.0 billion payable to Occidental by the Republic of Ecuador under a November 2015 International Center for Settlement of Investment Disputes arbitration award. This award relates to Ecuador's 2006 expropriation of Occidental's Participation Contract for Block 15. Occidental recorded a pre-tax gain of $681 million in the first quarter of 2016. The results related to Ecuador were presented as discontinued operations.
In May and June 2016, respectively, Occidental utilized part of the proceeds from the April 2016 senior notes offering (described below) to exercise the early redemption option on $1.25 billion of 1.75-percent senior notes due in the first quarter of 2017 and to retire all $750 million of 4.125-percent senior notes that matured in June 2016.
In April 2016, Occidental issued $2.75 billion of senior notes, comprised of $0.4 billion of 2.6-percent senior notes due 2022, $1.15 billion of 3.4-percent senior notes due 2026 and $1.2 billion of 4.4-percent senior notes due 2046. Occidental received net proceeds of approximately $2.72 billion. Interest on the senior notes is payable semi-annually in arrears in April and October of each year for each series of senior notes, beginning on October 15, 2016. Occidental used a portion of the proceeds to retire debt in May and June 2016, and used the remaining proceeds for general corporate purposes.
In March 2016, Occidental distributed its remaining shares of California Resources Corporation (California Resources) through a special stock dividend to stockholders of record as of February 29, 2016. Upon distribution, Occidental recorded a $78 million loss to reduce the investment to its fair market value, and Occidental no longer owns any shares of California Resources common stock.
In March 2016, Occidental completed the sale of its Piceance Basin operations in Colorado for $153 million resulting in a pre-tax gain of $121 million. The assets and liabilities related to these operations were presented as held for sale at December 31, 2015, and primarily included property, plant and equipment and current accrued liabilities and asset retirement obligations.
In February 2016, Occidental repaid $700 million of 2.5-percent senior notes that matured.
In January 2016, Occidental completed the sale of its Occidental Tower building in Dallas, Texas, for net proceeds of approximately $85 million, resulting in a pre-tax gain of $57 million. The building was classified as held for sale as of December 31, 2015.

2015
In January 2016, Occidental reached an understanding on the terms of payment for the approximate $1.0 billion payable to Occidental by the Republic of Ecuador under a November 2015 International Center for the Settlement of Investment Disputes arbitration award. This award relates to Ecuador's 2006 expropriation of Occidental's Participation Contract for Block 15. As of December 31, 2015, Occidental recorded a pre-tax gain of $322 million. The result of this settlement with Ecuador has been presented as discontinued operations.
In December 2015, Occidental entered a sales agreement to sell its Piceance Basin operations in Colorado for approximately $155 million. The transaction was completed in March 2016. As a result of exiting the Piceance Basin operations Occidental recorded certain contractual liabilities which are included in deferred credits and other liabilities - other on the consolidated balance sheet. The assets and liabilities related to these operations are presented as held for sale at December 31, 2015 and primarily include property, plant and equipment and current accrued liabilities and asset retirement obligations.
In November 2015, Occidental sold its Williston Basin assets in North Dakota for approximately $590 million.
In October 2015, Occidental completed the sale of its Westwood building in Los Angeles, California for net proceeds of $65 million.
In June 2015, Occidental issued $1.5 billion of debt that was comprised of $750 million of 3.50-percent senior unsecured notes due 2025 and $750 million of 4.625-percent senior unsecured notes due 2045. Occidental received net proceeds of


approximately $1.48 billion. Interest on the notes is payable semi-annually in arrears in June and December of each year for both series of notes, beginning on December 15, 2015.

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, Occidental's California oil and gas operations and related assets was spun-off through the pro rata distribution of 81.3 percent of the outstanding shares of common stock of California Resources, creating an independent, publicly traded company. See Note 17 Spin-off of California Resources Corporation.
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 included 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. Occidental’s average net production from the Hugoton Field properties in 2013The transaction was approximately 110 million cubic feet equivalent of natural gas per day, of which approximately 30 percent was oil. Occidental anticipates the transaction will be completed in the second quarter ofApril 2014 and, expects to report a gain on the sale. In February 2014, the Board of Directors authorized initiation of efforts to separate its California assetsafter taking into an independent and separately traded company.
2013
In October 2013, the Board of Directors authorized the pursuit of the sale of a minority interestaccount purchase price adjustments, it resulted in the Middle East/North Africa operations, the strategic alternatives for select assets, including oil and gas interests in the Williston Basin, Hugoton Field, Piceance Basin and other Rocky Mountain assets and the sale of a portion of Occidental’s investment in the Plains All-American Pipeline, L.P. (Plains Pipeline). 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.
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 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$1.3 billion. Occidental recorded a pre-tax gain on sale of $131$531 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 $2.3 billion for domestic oil and gas properties in the Permian Basin, Williston Basin, South Texas and California.
In November 2012, Occidental and Magellan Midstream Partners, L.P. (Magellan) formed BridgeTex Pipeline Company, LLC (BridgeTex) and are proceeding with construction of the BridgeTex Pipeline, which is expected to begin service in mid-2014. The approximately 450-mile-long pipeline will be capable of transporting approximately 300,000 barrels per day of crude oil between the Permian region (Colorado City, Texas) and Gulf Coast refinery markets. The BridgeTex Pipeline project also includes construction of approximately 2.6 million barrels of oil storage in aggregate.
Occidental owns a 50 percent interest in BridgeTex and the remaining 50 percent interest is owned by Magellan, which will be the operator. BridgeTex was determined to be a variable interest entity because of the difference between Occidental's economic interests and its decision-making rights. Occidental is the primary beneficiary and consequently consolidates BridgeTex. This investment is not material to Occidental's financial statements. At December 31, 2013 and 2012, the BridgeTex assets and liabilities mainly comprised cash and cash equivalents and PP&E. As of December 31, 2013, BridgeTex's total cash, PP&E and non-controlling amounts (reflecting Magellan's interests) were $82 million, $420 million and $246 million, respectively, and as of December 31, 2012, these amounts were $50 million, $9 million and $32 million, respectively. BridgeTex's assets cannot be used for the obligations of, nor do BridgeTex's creditors have recourse to, OPC or its other subsidiaries.

2011
During the year ended December 31, 2011, Occidental acquired producing properties in South Texas for approximately $1.8 billion.  Occidental also acquired approximately $2.6 billion of other domestic oil and gas assets, which included properties in California, as well as the Permian and Williston basins.
In the first quarter of 2011, Occidental completed the sale of its Argentine oil and gas operations.
Internationally, in the first quarter of 2011, Occidental acquired a 40-percent participating interest in the Al Hosn gas project in Abu Dhabi, joining with the Abu Dhabi National Oil Company in a 30-year joint venture agreement. The project is operated by Abu Dhabi Gas Development Company Limited. In May 2011, Occidental paid approximately $500 million for its share of pre-acquisition development expenditures.

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

NOTE 3ACCOUNTING AND DISCLOSURE CHANGES

RECENTLY ADOPTED ACCOUNTING AND DISCLOSURE CHANGES

Offsetting Assets and Liabilities
Beginning in the quarter ended March 31, 2013, Occidental adopted new disclosure requirements relating to its derivatives in accordance with rules issued byIn November 2016, the Financial Accounting Standards Board (FASB) in December 2011("FASB") issued new guidance related to the cash flow classification and January 2013. These new rules require tabular disclosurespresentation of the outstanding derivatives' grosschanges in restricted cash on the statement of cash flows. The rules become effective for the interim and net fair values, now including those derivativesannual periods beginning after December 15, 2017. Occidental is currently evaluating the impact of this guidance on its financial statements.
In October 2016, the FASB issued new guidance related to the income tax consequences of intra-entity transfers of assets other than inventory. The rules become effective for the interim and annual periods beginning after December 15, 2017. Occidental is currently evaluating the impact of these rules on its financial statements.
In August 2016, the FASB issued new guidance related to the classification of certain cash receipts and payments on the statement of cash flows. The rules become effective for the interim and annual periods beginning after December 15, 2017. Occidental is currently evaluating the impact of these rules on its financial statements.
In March, April, and May of 2016, the FASB issued rules clarifying several aspects of the new revenue recognition standard, previously issued in May 2014. The guidance is effective for interim and annual reporting periods starting January 1, 2018. Under the new standard, an entity will recognize revenue when it transfers promised goods or services to customers in an amount that arereflects what it expects to receive in exchange for the goods and services. The new standard also requires more detailed disclosures related to the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. Occidental will not early adopt the standard, and plans to use a modified retrospective approach upon adoption, with the cumulative effect of initial application recognized at the date of initial application subject to certain additional disclosures. Occidental has started the assessment process by evaluating its revenue streams and evaluating contracts under the revised standards. Occidental is currently evaluating the impact the standard is expected to have on its consolidated financial statements.
In March 2016, the FASB issued rules affecting entities that issue share-based payment awards to their employees. These rules are designed to simplify several aspects of accounting for share-based payment award transactions, including: (1) accounting and cash flow classification for excess tax benefits and deficiencies, (2) forfeitures, and (3) tax withholding requirements and cash flow classification. The rules were adopted for the second quarter of 2016 and did not have a master netting or similar arrangement and qualifymaterial impact on Occidental's financial statements upon adoption.
In March 2016, the FASB issued an update to eliminate the requirement to retrospectively adopt the equity method of accounting if an investment qualifies for net presentation, whether or not offsetuse of the equity method as a result of an increase in the consolidated balance sheet.level of ownership or degree of influence. The update requires that the equity method investor add the cost of acquiring the additional interest and adopt the equity method of accounting as of the date the investment becomes qualified for equity method accounting. The rules became effective for the interim and annual periods beginning after December 15, 2016. The rules do not have a material impact on Occidental's financial statements upon adoption.

Reclassification from Accumulated Other Comprehensive Income
Beginning in the quarter endedIn March 31, 2013, Occidental adopted new disclosure requirements for reporting amounts reclassified out of each component of accumulated other comprehensive income into the income statement in accordance with rules issued by2016, the FASB issued rules clarifying that a change in February 2013.

one of the parties to a derivative contract that is part of a hedge accounting relationship does not, by itself, require dedesignation of that relationship, as long as all other hedge accounting criteria continue to be met. The rules became effective for the interim and annual periods beginning after December 15, 2016. These new disclosures wererules do not have a material toimpact on Occidental's financial statements.


In February 2016, the FASB issued rules which require Occidental to recognize most leases, including operating leases, on the balance sheet. The new rules require lessees to recognize a right-of-use asset and lease liability for all leases with lease terms of more than 12 months. The lease liability represents the discounted obligation to make future minimum lease payments and corresponding right-of-use asset on the balance sheet for most leases. The guidance retains the current accounting for lessors and does not make significant changes to the recognition, measurement and presentation of expenses and cash flows by a lessee. Recognition, measurement and presentation of expenses and cash flows arising from a lease will depend on classification as a finance or operating lease. Occidental is the lessee under various agreements for real estate, equipment, plants and facilities, aircraft, and vehicles that are currently accounted for as operating leases, refer to Note 6, Lease Commitments. As a result, these new rules will increase reported assets and liabilities. Occidental will not early adopt this standard. Occidental will apply the revised lease rules for our interim and annual reporting periods starting January 1, 2019 using a modified retrospective approach, including several optional practical expedients related to leases commenced before the effective date. Occidental is currently evaluating the impact of these rules on its financial statements and has started the assessment process by evaluating the population of leases under the revised definition. The quantitative impacts of the new standard are dependent on the leases in force at the time of adoption. As a result, the evaluation of the effect of the new standards will extend over future periods.
In April 2015, the FASB issued rules simplifying the presentation of debt issuance costs. The new rules require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. Occidental adopted these rules retrospectively as of January 1, 2016. These rules do not have a material impact on Occidental's financial statements.

NOTE 4INVENTORIES

Net carrying values of inventories valued under the LIFO method were approximately $205$192 million and $185189 million at December 31, 20132016 and 20122015, respectively. Inventories consisted of the following:
Balance at December 31, (in millions) 2013 2012 2016 2015
Raw materials $74
 $70
 $65
 $73
Materials and supplies 628
 612
 446
 568
Finished goods 589
 763
 395
 395
 1,291
 1,445
 906
 1,036
LIFO reserve (91) (101)
Revaluation to LIFO (40) (50)
Total $1,200
 $1,344
 $866
 $986


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NOTE 5LONG-TERM DEBT

Long-term debt consisted of the following:
Balance at December 31, (in millions) 2013 2012 2016 2015
1.50% senior notes due 2018 $500
 $500
9.25% senior debentures due 2019 116
 116
4.10% senior notes due 2021 $1,249
 $1,300
 1,249
 1,249
3.125% senior notes due 2022 813
 813
2.60% senior notes due 2022 400
 —
2.70% senior notes due 2023 1,191
 1,191
8.75% medium-term notes due 2023 22
 22
3.50% senior notes due 2025 750
 750
3.40% senior notes due 2026 1,150
 —
3.00% senior notes due 2027 750
 —
7.20% senior debentures due 2028 82
 82
8.45% senior debentures due 2029 116
 116
4.625% senior notes due 2045 750
 750
4.40% senior notes due 2046 1,200
 —
4.10% senior notes due 2047 750
 —
2.50% senior notes due 2016 —
 700
4.125% senior notes due 2016 —
 750
1.75% senior notes due 2017 1,250
 1,250
 —
 1,250
2.70% senior notes due 2023 1,224
 1,250
3.125% senior notes due 2022 887
 900
4.125% senior notes due 2016 750
 750
2.5% senior notes due 2016 700
 700
1.45% senior notes due 2013 —
 600
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% and 0.13% as of December 31, 2013 and 2012, respectively) 68
 68
8.75% medium-term notes due 2023 22
 22
Variable rate bonds due 2030 (0.9% and 0.15% as of December 31, 2016 and 2015, respectively ) 68
 68
 6,964
 7,654
 9,907
 8,357
Less:        
Unamortized discount, net (25) (31) (36) (24)
Debt issuance costs (52) (28)
Current maturities —
 (600) —
 (1,450)
Total $6,939
 $7,023
 $9,819
 $6,855

Occidental has a bank credit facility (Credit Facility) with a $2.0 billion commitment expiring in 2016.2019. No amounts have been drawn under this Credit Facility. Up to $1.0$1.0 billion of the Credit Facility is available in the form of letters of credit. Borrowings under the Credit Facility bear interest at various benchmark rates, including LIBOR, plus a margin based on Occidental's senior debt ratings. Additionally, Occidental paid average annual facility fees of 0.08 percent in 20132016 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, 2013,2016, 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 December 2013, all $600November 2016, Occidental issued $1.5 billion of senior notes, comprised of $750 million of the outstanding 1.45-percent3.0-percent senior notes due 2013 matured. In addition, Occidental repurchased approximately $902027 and $750 million of various4.1-percent 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 2018.2047. Occidental received net proceeds of approximately $1.74 billion.$1.49 billion. Interest on the notes will be payable semi-annually in arrears in February and August for each series of notes.
In August 2011, Occidental issued $2.15 billion of debt, which comprised $1.25 billion of 1.75-percent senior unsecured notes due 2017 and $900 million of 3.125-percent senior unsecured notes due 2022. Occidental received net proceeds of approximately $2.1 billion. Interest on the notes is payable semi-annually in arrears in February and August each year for each series of notes.senior notes beginning August 15, 2017. Occidental will use the proceeds for general corporate purposes.
In March 2011,May and June 2016, respectively, Occidental redeemed all $1.0utilized part of the proceeds from the April 2016 senior notes offering (described below) to exercise the early redemption option on $1.25 billion of its outstanding 7-percent1.75-percent senior notes due 2013 and all $368 million of its outstanding 6.75-percent senior notes due 2012.  Occidental recorded a $163-million pre-tax charge related to this redemption in the first quarter of 2011.2017 and to retire all $750 million of 4.125-percent senior notes that matured in June 2016.
In April 2016, Occidental issued $2.75 billion of senior notes, comprised of $0.4 billion of 2.6-percent senior notes due 2022, $1.15 billion of 3.4-percent senior notes due 2026 and $1.2 billion of 4.4-percent senior notes due 2046. Occidental received net proceeds of approximately $2.72 billion. Interest on the senior notes is payable semi-annually in arrears in April and October of each year for each series of senior notes, beginning on October 15, 2016. Occidental used a portion of the proceeds to retire debt in May and June 2016, and used the remaining proceeds for general corporate purposes.
In February 2016, Occidental repaid $700 million of 2.5-percent senior notes that matured.
Occidental has provided guarantees on Dolphin Energy's debt, which are limited to certain political and other events. At December 31, 20132016 and 2012,2015, Occidental’s total guarantees were not material and a substantial majority of the amounts consisted of limited recourse guarantees on approximately $354$296 million and $370$318 million, respectively, of Dolphin’s debt. The fair value of the guarantees was immaterial.

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At December 31, 2013,2016, principal payments on long-term debt aggregated approximately $7.0$9.9 billion, of which nonezero is due in 2014 and 2015, $1.5 billion is due in 2016, $1.2 billion is due in 2017,, $0.5 billion is due in 2018, and $3.8 $0.1 billion is due in 2019, zero is due in 2020, $1.3 billion is due in 2021 and $8 billion is due in 2022 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, 20132016 and 2012,2015, substantially all of which were classified as Level 1, were approximately $7.1$10.9 billion and $8.2$8.4 billion, respectively, compared to carrying values of approximately $7.0$9.8 billion and $7.6$8.3 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, 20132016 and 2012,2015, variable-rate debt constituted approximately one percent of Occidental's total debt.

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, 20132016, future net minimum lease payments for noncancelable operating leases (excluding oil and gas and other mineral leases, utilities, taxes, insurance and maintenance expense) were the following:
In millions 
Amount (a)
2014 $141
2015 122
2016 97
(in millions) Amount
2017 89
 $255
2018 128
 230
2019 134
2020 100
2021 86
Thereafter 589
 469
Total minimum lease payments $1,166
 $1,274
(a)
These amounts are net of sublease rentals of $3 million, which are to be received in 2014.

Rental expense for operating leases net of sublease rental income for continuing operations, was $204$237 million in 20132016, $176$197 million in 20122015 and $179$155 million in 2011. Rental expense was net of sublease income of $3 million in 2013 and $4 million each in 2012 and 20112014.

NOTE 7DERIVATIVES

Objective & Strategy
Occidental uses a variety of derivative financial instruments and physical contracts, including cash-flow hedges and derivative instruments notthose designated as hedgingcash flow hedges, to manage its exposure to commodity price fluctuations, transportation commitments and to fix margins on the future sale of stored volumes of oil and natural gas. Where Occidental buys product for its own consumption or sells its production to a defined customer, Occidental elects normal purchases and normal sales exclusions. Occidental usually applies cash flow hedge accounting treatment to derivative financial instruments to obtainlock in margins on the average pricesforecasted sales of its natural gas storage volumes, and at times for other strategies to lock in margins. Occidental also enters into derivative financial instruments for speculative or trading purposes; however, the relevant production month andresults of any transactions are immaterial to improve realized prices for oil and gas. Occidental only occasionally hedges its oil and gas production, and, when it does so, the volumes are usually insignificant. Additionally, Occidental’s Phibro trading unit engages in trading activities using derivatives for the purpose of generating profits mainly from market price changes of commodities.
marketing portfolio. Refer to Note 1 for Occidental’s accounting policy on derivatives.
The financial instruments, not designated as hedges, will impact Occidental's earnings through mark-to-market until the offsetting future physical commodity is delivered. For GAAP purposes, any physical inventory is carried at lower of cost or market on the balance sheet. A substantial majority of Occidental's physical derivative contracts are index-based and carry no mark-to-market value in earnings. Net gains and losses associated with derivative instruments not designated as hedging instruments are recognized currently in net sales. Net gains and losses attributable to derivatives instruments subject to hedge accounting reside in accumulated other comprehensive income (loss) and are reclassified to earnings as the transactions to which the derivatives relate are recognized in earnings.

Cash-Flow Hedges
Occidental entered into financial swap agreements in November 2012 for the sale of a portion of its natural gas production in California. These swap agreements hedge 50 million cubic feet of natural gas per day beginning in January 2013 through March 2014 and qualify as cash-flow hedges. The weighted-average strike price of these swaps is $4.30.
Through March 31, 2012, Occidental held financial swap agreements related to the sale of 50 million cubic feet per day of its existing natural gas production from the Rocky Mountain region of the United States that qualified as cash-flow hedges at a weighted-average strike price of $6.07.
Through December 31, 2011, Occidental held a series of collar agreements for 12,000 barrels of oil per day of its domestic production that qualified as cash-flow hedges at a weighted-average strike price that ranged from $32.92 to $46.35.
Occidental’s marketing and trading operations store natural gas purchased from third parties at Occidental’s North American leased storage facilities. Derivative instruments are used to fix margins on the future sales of the stored volumesvolumes. These agreements continue through March 31, 2014.2017. As of December 31, 2013 and 2012,2016, Occidental had approximately 117 billion cubic feet and 20 billion cubic feet(Bcf) of natural gas held in storage, respectively. As of December 31, 2013and2012, Occidental had cash-flow hedges for the forecast sale,forecasted sales, to be settled by physical delivery, of approximately 13 billion cubic feet and 20 billion cubic feet7 Bcf of this stored natural gas. As of December 31, 2015, Occidental had approximately 13 Bcf of natural gas respectively.

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The following table presents the after-tax gainsheld in storage, and losses recognized in, and reclassified to income from, AOCI, for derivative instruments classified ashad cash-flow hedges for the years ended December 31, 2013 and 2012 (in millions):

  After-tax
  2013 2012
Beginning Balance — AOCI $(7) $1
Unrealized (losses) gains recognized in AOCI (3) 16
Gains reclassified to income (4) (24)
Ending Balance — AOCI $(14) $(7)

Occidental expectsforecasted sales, to reclassify an insignificant amount, based on the valuation asbe settled by physical delivery, of December 31, 2013,approximately 14 Bcf of net after-tax derivative losses from AOCI into income during the next 12 months.stored natural gas. The gains and losses reclassified to income were recognized in net sales, and the amount of cash-flow hedges, including the ineffective portion of cash-flow hedges was immaterial for the years ended December 31, 20132016 and 2012.2015.



Derivatives Not Designated as Hedging Instruments
The following table summarizes Occidental'sthe amounts reported in net volumes ofsales related to the outstanding commodity derivatives contractsderivative instruments not designated as hedging instruments including both financial and physical derivative contracts as of December 31, 20132016 and 2012:2015:
  
Net Outstanding Position
Long / (Short)
Commodity 2013 2012
Oil (million barrels) (22) (4)
Natural gas (billion cubic feet) (10) (170)
Precious metals (million troy ounces) 1
 1
   
 As of December 31, (in millions, except Long/(Short) volumes) 2016 2015
Gain (loss) on derivatives not designated as hedges    
Oil commodity contracts $(5) $28
Natural gas commodity contracts $1
 $(26)
     
Outstanding net volumes on derivatives not designated as hedges    
Oil Commodity Contracts    
Volume (MMBOE) 67
 83
Price Per Bbl $53.86
 $45.25
     
Natural gas commodity contracts    
Volume (Bcf) (12) (5)
Price Per MMBTU $3.19
 $2.72

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.
In addition, Occidental typically has certain other commodity trading contracts, such as agricultural products, power and other metals, as well as foreign exchange contracts. These contracts were not material to Occidental as of December 31, 2013 and 2012.
Occidental fulfills its short positions through its own production or by third-party purchase contracts. Subsequent to December 31, 2013, 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 $11 million and $49 million of net gains from derivatives not designated as hedging instruments were recognized in net sales for the years ended December 31, 2013 and 2012, respectively.


57


Fair Value of Derivatives
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. The following table presentssummarizes the grossfair value of the Company’s derivative assets and net fair values of Occidental’s outstanding derivatives as of December 31, 2013 and 2012 (in millions):liabilities by input level within the fair-value hierarchy:
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 (b) (d)
   (329)   (364)
Total net fair value of derivatives   $51
   $58

December 31, 2012 
Asset Derivatives
Balance Sheet Location
 Fair Value 
Liability Derivatives
Balance Sheet Location
 Fair Value
As of December 31, 2016As of December 31, 2016 Fair Value Measurements Using 
Netting (b)
 Total Fair Value
(in millions) Balance Sheet Location Level 1 Level 2 Level 3 
Assets:          
Cash-flow hedges (a)
                   
Commodity contracts Other current assets $11
 Accrued liabilities $1
 Other current assets —
 1
 —
 —
 1
Long-term receivables and other assets, net —
 Deferred credits and other liabilities 1
 Long-term receivables and other assets, net —
 —
 —
 —
 —
   $11
   $2
Derivatives not designated as hedging instruments (a)
        
Derivatives not designated as hedging instruments (a)
 

 

      
Commodity contracts Other current assets $386
 Accrued liabilities $479
 Other current assets 166
 57
 —
 (196) 27
Long-term receivables and other assets, net 22
 Deferred credits and other liabilities 16
 Long-term receivables and other assets, net 2
 3
 —
 (2) 3
   408
   495
Total gross fair value   419
   497
Less: counterparty netting and cash collateral (c) (d)
   (301)   (371)
Total net fair value of derivatives   $118
   $126
Liabilities:          
Cash-flow hedges (a)
           
Commodity contracts Accrued liabilities —
 6
 —
 —
 6
Deferred credits and liabilities —
 —
 —
 —
 —
Derivatives not designated as hedging instruments (a)
Derivatives not designated as hedging instruments (a)
          
Commodity contracts Accrued liabilities 172
 51
 —
 (196) 27
Deferred credits and liabilities 1
 6
 —
 (2) 5
(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)
These amounts do not include collateral. As of December 31, 2013,2016, collateral received of $11$4 million has been netted against derivative assets and collateral paid of $46$13 million has been netted against derivative liabilities.
(c)
As of December 31, 2012, collateral received of $25 million has been netted against derivative assets and collateral paid of $95 million has been netted against derivative liabilities.
(d)Select clearinghouses and brokers require Occidental to post an initial margin deposit. Collateral, mainly for initial margin, of $103$25 million and $116 millionas of December 31, 2016, 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 sheetssheets. These amounts do not include collateral.


As of December 31, 2015 Fair Value Measurements Using 
Netting (b)
 Total Fair Value
(in millions) Balance Sheet Location Level 1 Level 2 Level 3  
Assets:            
Cash-flow hedges (a)
            
Commodity contracts Other current assets —
 8
 —
 —
 8
 Long-term receivables and other assets, net —
 —
 —
 —
 —
Derivatives not designated as hedging instruments (a)
          
Commodity contracts Other current assets 554
 72
 —
 (519) 107
 Long-term receivables and other assets, net 3
 6
 —
 (2) 7
Liabilities:            
Cash-flow hedges (a)
            
Commodity contracts Accrued liabilities —
 1
 —
   1
 Deferred credits and liabilities —
 —
 —
 —
 —
Derivatives not designated as hedging instruments (a)
          
Commodity contracts Accrued liabilities 541
 84
 —
 (519) 106
 Deferred credits and liabilities 3
 5
 —
 (2) 6
(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)These amounts do not include collateral. As of December 31, 2015, collateral received of $14 million has been netted against derivative assets and collateral paid of $4 million has been netted against derivative liabilities. Select clearinghouses and brokers require Occidental to post an initial margin deposit. Collateral, mainly for initial margin, of $3 million as of December 31, 2013 and 2012, respectively.2015, 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. These amounts do not include collateral.

See Note 15 for fair value measurement disclosures on derivatives.


58


Credit Risk
A substantial portionThe majority of Occidental’s derivative transaction volumeOccidental's counterparty credit risk is executedrelated to the physical delivery of energy commodities to its customers and their inability to meet their settlement commitments. Occidental manages credit risk by selecting counterparties that it believes to be financially strong, by entering into master netting arrangements with counterparties and by requiring collateral or other credit risk mitigants, as appropriate. Occidental actively evaluates the creditworthiness of its counterparties, assigns appropriate credit limits, and monitors credit exposures against those assigned limits. Occidental also enters into future contracts through exchange-traded contracts,regulated exchanges with select clearinghouses and brokers, which are subject to minimal credit risk as a significant portion of these transactions is settledsettle 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.basis.
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, 2013 and 2012, Occidental had a net liability of $8 million and $34 million, respectively, which are net of collateral posted of $23 million and $64 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, 20132016 and 2012.

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, 2013, the2015. The aggregate fair value of foreign currency derivatives used in the trading operationsderivative instruments with credit-risk-related contingent features for which a net liability position existed was immaterial. The effect of exchange rates on transactions in foreign currencies is included in periodic income.immaterial for both December 31, 2016, and December 31, 2015.

NOTE 8ENVIRONMENTAL 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.

ENVIRONMENTAL REMEDIATION
As of December 31, 2013,2016, Occidental participated in or monitored remedial activities or proceedings at 157147 sites. The following table presents Occidental’s environmental remediation reserves as of December 31, 2013, 20122016, 2015 and 2011,2014, the current portion of which is included in accrued liabilities ($78 million in 2013, $80($131 million in 20122016, $70 million in 2015, and $79$79 million in 2011) 2014)


and the remainder in deferred credits and other liabilities — other ($252 million in 2013, $264($739 million in 2012 and $2812016, $316 million in 2011)2015, and $255 million in 2014). 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)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 2013 2012 2011
($ amounts in millions) 2016 2015 2014
 Number of Sites 
Reserve
Balance
 Number of Sites Reserve Balance Number of Sites Reserve Balance Number of Sites 
Reserve
Balance
 Number of Sites Reserve Balance Number of Sites Reserve Balance
NPL sites 31
 $25
 35
 $54
 36
 $63
 33
 $461
 34
 $27
 30
 $23
Third-party sites 74
 83
 75
 84
 73
 88
 68
 163
 66
 128
 67
 101
Occidental-operated sites 20
 118
 22
 123
 22
 120
 17
 106
 18
 107
 17
 107
Closed or non-operated Occidental sites 32
 104
 29
 83
 29
 89
 29
 140
 31
 124
 31
 103
Total 157
 $330
 161
 $344
 160
 $360
 147
 $870
 149

$386

145

$334

As of December 31, 2013,2016, Occidental’s environmental reserves exceeded $10$10 million each at 1016 of the 157147 sites described above, and 10888 of the sites had reserves from $0 to $1$1 million each.
As of December 31, 2013, two2016, three sites — the Diamond Alkali Superfund Site and a former chemical plant in Ohio (both of which are indemnified by Maxus Energy Corporation, as discussed further below), and a landfill in western New York owned by Occidental and a former facility inWestern New York — accounted for 6095 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 14The reserve balance above includes 17 NPL sites subject to indemnification by Maxus.
Four of the remaining NPL sites.

59


As of December 31, 2013, Maxus has also retained the liability and is indemnifying Occidental for 8 of the 74 third-party sites. Three of the remaining 6668 third-party sites —a Maxus-indemnified chrome site in New Jersey, a former copper mining and smelting operation in Tennessee, a containment and removal project in Tennesseean active plant outside of the United States and an active refinery in Louisiana where Occidental reimburses the current owner for certain remediation activities — accounted for 5253 percent of Occidental’s reserves associated with these sites. The reserve balance above includes 9 third-party sites subject to indemnification by Maxus.
FourThree sites — chemical plants in Kansas, Louisiana, and New York and a group of oil and gas properties in the southwestern United States —Texas accounted for 6148 percent of the reserves associated with the Occidental-operated sites.
FourSix other sites — a landfill in western New York, former chemical plants in Tennessee, Delaware, Washington and DelawareCalifornia, and a closed coal mine in Pennsylvania — accounted for 6469 percent of the reserves associated with closed or non-operated Occidental sites.
When Occidental acquired Diamond Shamrock Chemicals Company (DSCC) in 1986, Maxus Energy Corporation (Maxus), currently a subsidiary of YPF S.A. (YPF), agreed to indemnify Occidental for a number of environmental sites, including the Diamond Alkali Superfund Site (Site) along a portion of the Passaic River. On June 17, 2016, Maxus and several affiliated companies filed for Chapter 11 bankruptcy in Federal District Court in the State of Delaware. Prior to filing for bankruptcy, Maxus defended and indemnified Occidental in connection with clean-up and other costs associated with the sites subject to the indemnity, including the Site. Occidental is pursuing Maxus and its parent company, YPF, as the alter ego of Maxus, to recover all indemnified costs, which will include costs to be incurred at the Site.
In March 2016, the EPA issued a Record of Decision (ROD) specifying remedial actions required for the lower 8.3 miles of the Lower Passaic River. The ROD does not address any potential remedial action for the upper nine miles of the Lower Passaic River or Newark Bay. During the third quarter of 2016, and following Maxus’s bankruptcy filing, Occidental and the EPA entered into an Administrative Order on Consent (AOC) to complete the design of the proposed clean-up plan outlined in the ROD at an estimated cost of $165 million. The EPA announced that it will pursue similar agreements with other potentially responsible parties.
Occidental has accrued a reserve relating to its estimated allocable share of the costs to perform the design and the remediation called for in the AOC and the ROD, as well as for certain other Maxus-indemnified sites. Occidental’s ultimate share of this liability may be higher or lower than the reserved amount, and is subject to final design plans and the resolution of Occidental's allocable share with other potentially responsible parties. Occidental continues to evaluate the costs to be incurred to comply with the AOC, the ROD and to perform remediation at other Maxus-indemnified sites in light of the Maxus bankruptcy and the share of ultimate liability of other potentially responsible parties.
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 2013 2012 2011
Balance — Beginning of Year $344
 $360
 $366
Remediation expenses and interest accretion 60
 56
 53
Changes from acquisitions/dispositions —
 —
 14
Payments (74) (72) (73)
Balance — End of Year $330
 $344
 $360

Based on current estimates, Occidental expects to expend funds corresponding to approximately half40 percent 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.$1.0 billion.



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 2013 2012 2011
(in millions) 2016 2015 2014
Operating Expenses            
Oil and Gas $137
 $160
 $158
 $65
 $93
 $103
Chemical 75
 70
 68
 75
 74
 80
Midstream and Marketing 17
 20
 21
 11
 13
 11
 $229
 $250
 $247
 $151
 $180
 $194
Capital Expenditures            
Oil and Gas $97
 $122
 $110
 $43
 $122
 $143
Chemical 14
 18
 15
 25
 41
 35
Midstream and Marketing 7
 12
 15
 5
 4
 11
 $118
 $152
 $140
 $73
 $167

$189
Remediation Expenses            
Corporate $60
 $56
 $52
 $61
 $117
 $79

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 9LAWSUITS, CLAIMS, COMMITMENTS AND CONTINGENCIES

OPCOccidental 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. OPCOccidental 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 OPCOccidental 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.

60


In accordance with applicable accounting guidance, 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. In Note 8, Occidental has disclosed its reserve balances for environmental matters.remediation matters that satisfy this criteria. Reserve balances for matters, other mattersthan environmental remediation, that satisfy this criteria as of December 31, 20132016 and 2012,December 31, 2015 were not material to Occidental'sOccidental’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 disclosedoutstanding lawsuits, claims and proceedings and discloses its estimable range of reasonably possible additional losses for sites where it is a participant in environmental remediation. Occidental believes that other reasonably possible losses for non-environmental matters 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. Occidental reassesses the probability and estimability of contingent losses as new information becomes available.

Tax Matters

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 whichthat are subject to IRS review. Taxable years from 20002002 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.



Indemnities to Third Parties

Occidental, 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, 2016, 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.

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, 2013,2016, total purchase obligations were $10.0$8.9 billion, which included approximately $3.0 billion, $1.7 billion, $1.0$1.2 billion, $0.6$0.9 billion, $0.8 billion and $0.8$0.7 billion that will be paid in 2014, 2015, 2016, 2017, 2018, 2019, 2020 and 2018,2021, respectively. Included in the purchase obligations are commitments for major fixed and determinable capital expenditures during 20142017 and thereafter, which were approximately $2.1$0.5 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, 2013, 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 10DOMESTIC AND FOREIGN INCOME TAXES

The domestic and foreign components of income (loss) from continuing operations before domestic and foreign income taxes were as follows:
For the years ended December 31, (in millions) Domestic Foreign Total
2013 $4,930
 $4,747
 $9,677
2012 $2,117
 $5,636
 $7,753
2011 $4,806
 $6,035
 $10,841
For the years ended December 31, (in millions) Domestic Foreign Total
2016 $(2,698) $1,034
 $(1,664)
2015 $(5,810) $(3,666) $(9,476)
2014 $(732) $2,273
 $1,541

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 
United States
Federal
 
State
and Local
 Foreign Total
2013        
2016        
Current $361
 $37
 $2,170
 $2,568
 $(784) $9
 $630
 $(145)
Deferred 1,145
 59
 (17) 1,187
 (505) (19) 7
 (517)
 $1,506
 $96
 $2,153
 $3,755
 $(1,289) $(10) $637
 $(662)
2012        
2015        
Current $(401) $8
 $2,383
 $1,990
 $(810) $(31) $883
 $42
Deferred 1,046
 41
 41
 1,128
 (1,146) (83) (143) (1,372)
 $645
 $49
 $2,424
 $3,118
 $(1,956) $(114) $740
 $(1,330)
2011        
2014        
Current $320
 $88
 $2,357
 $2,765
 $870
 $81
 $1,912
 $2,863
Deferred 1,340
 47
 49
 1,436
 (1,037) (71) (70) (1,178)
 $1,660
 $135
 $2,406
 $4,201
 $(167) $10
 $1,842
 $1,685

61


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, 2013 2012 2011 2016 2015 2014
United States federal statutory tax rate 35 % 35 % 35 % 35 % 35 % 35 %
Other than temporary loss on available for sale investment in California Resources stock (2) (1) 12
Enhanced oil recovery credit 5
 —
 —
Tax benefit due to write off of exploration blocks 14
 —
 —
Operations outside the United States 4
 5
 4
 (14) (21) 65
State income taxes, net of federal benefit 1
 1
 1
 —
 1
 1
Other (1) (1) (1) 2
 —
 (4)
Worldwide effective tax rate 39 % 40 % 39 % 40 % 14 % 109 %



The tax effects of temporary differences resulting in deferred income taxes at December 31, 20132016 and 20122015 were as follows:
 2013 2012 2016 2015
Tax effects of temporary differences (in millions) Deferred Tax Assets Deferred Tax Liabilities Deferred Tax Assets Deferred Tax Liabilities Deferred Tax Assets Deferred Tax Liabilities Deferred Tax Assets Deferred Tax Liabilities
Property, plant and equipment differences $—
 $8,363
 $—
 $7,316
 $—
 $3,345
 $—
 $3,232
Equity investments, partnerships and foreign subsidiaries —
 225
 —
 351
 —
 58
 —
 12
Environmental reserves 121
 —
 126
 —
 314
 —
 136
 —
Postretirement benefit accruals 376
 —
 413
 —
 342
 —
 346
 —
Deferred compensation and benefits 222
 —
 278
 —
 222
 —
 179
 —
Asset retirement obligations 407
 —
 367
 —
 406
 —
 372
 —
Foreign tax credit carryforwards 1,091
 —
 1,277
 —
 2,046
 —
 2,034
 —
Other tax credit carryforwards —
 —
 195
 —
Alternative minimum tax credit carryforwards 226
 —
 —
 —
General business credit carryforwards 186
 —
 —
 —
Federal benefit of state income taxes 136
 —
 89
 —
 8
 —
 11
 —
All other 344
 82
 334
 161
 370
 —
 677
 —
Subtotal 2,697
 8,670
 3,079
 7,828
 4,120
 3,403
 3,755
 3,244
Valuation allowance (1,074) —
 (1,040) —
 (1,849) —
 (1,834) —
Total deferred taxes $1,623
 $8,670
 $2,039
 $7,828
 $2,271
 $3,403
 $1,921
 $3,244

The current portion of total deferred tax assets was$150 million and $250 million as of December 31, 2013 and 2012, respectively, which was reported in other current assets. Total deferred tax assets were $1.6$2.3 billion and $2.0$1.9 billion as of December 31, 20132016 and 2012, respectively, the noncurrent portion of which is netted against deferred tax liabilities.2015, respectively. 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 the net deferred tax liabilities is primarily related to the addition of deferred tax benefits associated with various tax credit carryforwards as well as a net reduction in the deferred tax asset related to the allowance for bad debts.
Occidental had, as of December 31, 2013,2016, foreign tax credit carryforwardscarryforward of $1.1$2.0 billion, which expire in varying amounts through 2022,2026, and various state operating loss carryforwards, which have varying carryforward periods through 2025.2036. In addition, Occidental had, as of December 31, 2016, alternative minimum tax credit carryforwards of $226 million, that do not expire, and $186 million of general business credit carryforwards that expire between 2023 and 2036. Occidental's valuation allowance provides for substantially all of the foreign tax credit and state operating loss carryforwards.credit.
A deferred tax liability has not been recognized for temporary differences related to unremitted earnings of certain consolidated foreign subsidiaries aggregating approximately $10.6$8.5 billion, net of foreign taxes, at December 31, 20132016 , 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 $134$116 million would be required, assuming utilization of available foreign tax credits.
Discontinued operations include income tax charges of $9$249 million, $7$1 million, and $86$454 million in 2013, 20122016, 2015, and 2011,2014, respectively.
Additional paid-in capital was credited $6 million in 2013, $8 million in 2012 and $14 million in 2011 for an excess tax benefit from the exercise of certain stock-based compensation awards.
As of December 31, 2013,2016, Occidental had liabilities for unrecognized tax benefits of approximately $61$22 million included in deferred credits and other liabilities – other, all of which, if subsequently recognized, would favorably affect Occidental’s effective tax rate.


62


A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:
For the years ended December 31, (in millions) 2013 2012 2016 2015
Balance at January 1, $76
 $67
 $22
 $61
Additions based on tax positions related to the current year —
 16
Reductions based on tax positions related to prior years and settlements (15) (7) —
 (39)
Balance at December 31, $61
 $76
 $22
 $22

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 has recognized $761 million and $297 million in income tax receivables at December 31, 2016 and 2015, respectively, which were recorded in other current assets.
Occidental is subject to audit by various tax authorities in varying periods. See Note 9 for a discussion of these matters.
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, 2013, 20122016, 2015 and 2011.2014.



NOTE 11STOCKHOLDERS' EQUITY

The following is a summary of common stock issuances:
Shares in thousands Common Stock
Balance, December 31, 20102013 885,275889,919
Issued 1,302584
Options exercised and other, net 23255
Balance, December 31, 20112014 886,809890,558
Issued 1,746782
Options exercised and other, net 24620
Balance, December 31, 20122015 888,801891,360
Issued 826843
Options exercised and other, net 29212
Balance, December 31, 20132016 889,919892,215

TREASURY STOCK
In FebruaryOn October 2, 2014, Occidental increased the total number of shares authorized for its share repurchase program by 3060 million from 95shares to 185 million shares;shares total; however, the program does not obligate Occidental to acquire any specific number of shares and may be discontinued at any time. No shares were purchased under the program in 2016. In 2013 and 2012, respectively,2015 Occidental purchased 10.3 million and 7.27.4 million shares under the program at an average cost of $94.42 and $77.98$76.99 per share.
Additionally, Occidental purchased shares from the trustee of its defined contribution savings plan during each year.
As of December 31, 20132016, 20122015 and 20112014, treasury stock shares numbered 93.9128.0 million, 83.3127.7 million and 75.8120.0 million, respectively.

NONREDEEMABLE PREFERRED STOCK
Occidental has authorized 50,000,000 shares of preferred stock with a par value of $1.00$1.00 per share. At December 31, 2013, 20122016, 2015 and 2011,2014, Occidental had no outstanding shares of preferred stock.


63


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 2013 2012 2011
Basic EPS      
Income from continuing operations $5,922
 $4,635
 $6,640
Discontinued operations, net (19) (37) 131
Net income 5,903
 4,598
 6,771
Less: Net income allocated to participating securities (13) (8) (11)
Net income, net of participating securities $5,890
 $4,590
 $6,760
Weighted average number of basic shares 804.1
 809.3
 812.1
Basic EPS $7.33
 $5.67
 $8.32
       
Diluted EPS      
Net income, net of participating securities $5,890
 $4,590
 $6,760
Weighted average number of basic shares 804.1
 809.3
 812.1
Dilutive securities 0.5
 0.7
 0.8
Total diluted weighted average common shares 804.6
 810.0
 812.9
Diluted EPS $7.32
 $5.67
 $8.32
(in millions, except per-share amounts) 2016 2015 2014
       
Income (loss) from continuing operations $(1,002) $(8,146) $(130)
Less: Income from continuing operations attributable to noncontrolling interest —
 —
 (14)
Income (loss) from contributing operations attributable to common stock (1,002) (8,146) (144)
Income from discontinued operations 428
 317
 760
Net income (loss) (574) (7,829) 616
Less: Net income allocated to participating securities —
 —
 —
Net income (loss), net of participating securities $(574) $(7,829) $616
Weighted average number of basic shares 763.8
 765.6
 781.1
Basic earnings (loss) per common share $(0.75) $(10.23) $0.79
       
Net income (loss), net of participating securities $(574) $(7,829) $616
Weighted average number of basic shares 763.8
 765.6
 781.1
Dilutive securities —
 —
 —
Total diluted weighted average common shares 763.8
 765.6
 781.1
Diluted earnings (loss) per common share $(0.75) $(10.23) $0.79



ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)LOSS
Accumulated other comprehensive loss consisted of the following after-tax amounts:
Balance at December 31, (in millions) 2013 2012 2016 2015
Foreign currency translation adjustments $(5) $(34) $(10) $(9)
Unrealized losses on derivatives (14) (7) (13) (7)
Pension and post-retirement adjustments (a)
 (284) (461) (243) (291)
Total $(303) $(502) $(266) $(307)
(a)See Note 13 for further information.

NOTE 12STOCK-BASED INCENTIVE PLANS

Occidental has established several Plansplans 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 6635 million shares of Occidental common stock were authorized for issuance and approximately 164.5 million shares had been issuedallocated to employee awards through December 31, 2013. Of2016. In accordance with the remainingterms of the shareholder approved 2015 Long-Term Incentive Plan (LTIP), awards issued under the superseded 2005 LTIP and subsequently forfeited after adoption of the 2015 LTIP increase the shares onlyavailable for issuance under the 2015 LTIP. As of December 31, 2016, approximately 2030 million shares arewere available for grants of future awards because aawards. The 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 2030 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.cash, including awards that were issued under a previous plan that remain outstanding.
During 2013,2016, non-employee directors were granted awards for 37,10023,888 shares of restricted stock, a substantial majority of which fully vested on the grant date.common stock. Compensation expense for these awards was measured using the closing quoted market price of Occidental's common stock on the grant date and was fully recognized at that time.
The following table summarizes certain stock-based incentive amountstotal share-based compensation expense recognized in income related to continuing and discontinued operations and the associated tax benefit for the past three years:years ended December 31:
For the years ended December 31, (in millions) 2013 2012 2011 2016 2015 2014
Compensation expense $152
 $78
 $110
 $121
 $49
 $129
Income tax benefit recognized in the income statement $55
 $29
 $40
 43
 17
 46
Intrinsic value of options and stock-settled SARs exercised $24
 $18
 $21
Cash paid (a)
 $96
 $83
 $124
Fair value of RSUs and TSRIs vested during the year (b)
 $83
 $28
 $53
(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.

64


As of December 31, 20132016, unrecognized compensation expense for all unvested stock-based incentive awards based on year-end valuation, was $205$231 million. This expense is expected to be recognized over a weighted-average period of 2.02.2 years.

RSUs
Certain employees are awarded the right to receive RSUs, some of which have performance criteria based on net income or earnings per share, 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 threefrom one to four 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 orbetween one to three years, dividend equivalents are accumulated during the vesting or performance period, as appropriate, and are paid when they vest.upon vesting or performance certification, as appropriate.
The weighted-average, grant-date fair values of cash-settled RSUs granted in 2013, 20122016, 2015 and 20112014 were $89.70, $84.38$75.57, $72.64, and $104.74$100.95 per share, respectively. The weighted-average, grant-date fair values of the stock-settled RSUs granted in 20132016, 20122015, and 20112014 were $90.35, $84.81$74.82, $72.54, and $102.97,$101.77, respectively. Cash-Settled RSUs resulted in payments of $41 million, $39 million, and $64 million during the years ended December 31, 2016, 2015, and 2014, respectively. The fair value of RSUs settled in shares during the years ended December 31, 2016, 2015, and 2014 was $31 million, $28 million, and $56 million, respectively.


A summary of changes in Occidental’s unvested cash- and stock-settled RSUs during the year ended December 31, 20132016 is presented below:
 Cash-Settled Stock-Settled Cash-Settled Stock-Settled
 
RSUs
(000's)
 
Weighted-Average
Grant-Date
Fair Value
 
RSUs
(000's)
 
Weighted-Average
Grant-Date
Fair Value
 
RSUs
(000's)
 
Weighted-Average
Grant-Date
Fair Value
 
RSUs
(000's)
 
Weighted-Average
Grant-Date
Fair Value
Unvested at January 1 1,332
 $90.27 1,375
 $88.23 1,130
 $81.06
  1,758
 $81.19
 
Granted 785
 89.70 793
 90.35 53
 75.57
 2,238
 74.82
 
Vested (613) 89.89 (438) 84.51 (536) 83.18
 (417) 82.35
 
Forfeitures (73) 90.26 (123) 88.59 (46) 80.89
 (79) 77.00
 
Unvested at December 31 1,431
  90.12 1,607
  90.26 601
  78.70
  3,500
  77.07
 

TSRIs
Certain executives are awarded TSRIs that vest at the end of a three-year period following the grant date ifdate. Payout is based upon Occidental's total shareholder return performance targets are certified as being met.relative to its peers and the S&P 500. TSRIs granted in 2016 and 2015 have payouts that range from 0 to 200 percent of the target award. TSRIs granted in July 2013 and 20122014 have payouts that range from 0 to 150 percent of the target award and 0 to 100 percent of the maximum award, respectively, that wouldaward; all outstanding TSRIs settle once certified, fully in stock. TSRIs granted in July 2011 have payouts that range from 0 to 100 percent of the maximum award that would settle,stock once certified, 50 percent in stock and 50 percent in cash.certified. Dividend equivalents for TSRIs are accumulated and paid upon vesting forcertification of the numberaward. The fair value of vested shares.TSRIs settled in shares during the years ended December 31, 2016, 2015, and 2014 was $8 million, $14 million, and zero, respectively.
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 TSRIs
Year Granted 2013 2012 2011 2016 2015 2014
Assumptions used:            
Risk-free interest rate 0.6% 0.4% 0.6% 0.8% 0.9% 1.0%
Dividend yield 2.8% 2.6% 1.8% 3.9% 4.1% 2.8%
Volatility factor 30% 34% 33% 42% 37% 27%
Expected life (years) 3
 3
 3
 3
 3
 3
Grant-date fair value of underlying Occidental common stock $91.97
 $84.57
 $102.97
 $76.83
 $72.54
 $101.95


65


A summary of Occidental’s unvested TSRIs as of December 31, 20132016, and changes during the year ended December 31, 20132016, is presented below:
 TSRIs TSRIs
 
Awards
(000’s)
 
Weighted-Average
Grant-Date Fair
Value of Occidental Stock
 
Awards
(000’s)
 
Weighted-Average
Grant-Date Fair
Value of Occidental Stock
Unvested at January 1 (a)
 1,930
 $80.39 346
 $83.75
 
Granted (a)
 135
  91.97 473
 76.83
 
Vested (a)
 (1,143)  72.44 (102) 87.27
 
Forfeitures (90)  87.05 (10) 76.43
 
Unvested at December 31 (a)
 832
  92.49 707
  78.72
 
(a)
Presented at the target or mid-point payouts.

STOCK OPTIONS AND SARs
Certain employees have been granted Stock Appreciation Rights (SAR) or Options that are settled in stock and SARs that are settled either only in stock or only in cash. No Options or SARs have been granted since 2006 and all outstanding awards are vested.stock. Exercise prices of the Options and SARs were equal to the quoted market value of Occidental’s stock on the grant date. Generally,No options were granted in 2016. The intrinsic value of options and stock-settled SARs exercised during the Options years ended December 31, 2016, 2015,


and SARs vest ratably over three years from the grant date with a maximum term2014 was $1 million, zero, and $5 million, respectively. In 2014, cash payments of ten years. These Options$26 million were made for cash - settled SAR awards granted in 2004. In 2015 and SARs may be forfeited2016 no cash based SAR awards were granted or accelerated under certain circumstances.outstanding.
The fair value of each Option stock-settled SAR or cash-settledstock-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 activityvesting and expiration terms of the grantee population at the grant date.award. 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, 20132016:

 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)
 SARs & Options (000's) Weighted-Average Exercise Price Weighted-Average Remaining Contractual Term (yrs) Aggregate Intrinsic Value (000’s)
Beginning balance, January 1 494
 $24.66
     537
 $31.88
     629
 $77.58
  
  
Exercised (142) $24.66
   (391) $28.12
   (47) 45.53
    
Forfeitures —
 $—
   (1) $15.57
  
Granted —
 —
    
Forfeited (11) 79.98
    
Ending balance, December 31 352
 $24.66
 0.5 $24,783
 145
 $42.11
 1.9 $7,701
 571
 79.98
 5.1
 $—
Exercisable at December 31 352
 $24.66
 0.5 $24,783
 145
 $42.11
 1.9 $7,701
 214
 79.98
 5.1
 $—

OTHERROCEI / ROAI
During 2013, Occidental also granted approximately 160,000grants share-equivalents to certain employees that vest at the end of a three-year period beginning January 1, 2014, if performance targets based on returnsreturn on assets of the applicable segment or return on capital employed are certified as being met. These awards are settled in stock atupon certification of the time of vesting,performance target, with payouts that range from 0 to 200 percent of the target award. Dividend equivalents are accumulated and paid upon vesting forcertification of the number of vested shares. The weighted-average, grant-date fair value of these awards was $80.98.award.


66


  ROCEI / ROAI
  
Awards
(000's)
 
Weighted-Average
Grant-Date
Fair Value of Occidental Stock
Unvested at January 1 392
  $85.43
 
Unvested at December 31 392
  85.43
 

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 $166$163 million and $145$175 million as of December 31, 20132016 and 2012,2015, respectively, and Occidental expensed $140 million in 2013, $137 million in 2012 and $110$113 million in 20112016, $136 million in 2015 and $146 million in 2014 under the provisions of these defined contribution and supplemental retirement plans.

DEFINED BENEFIT PLANS
Participation in defined benefit plans is limited and approximately 1,000600 domestic and 1,5001,100 foreign national employees, mainly union, nonunion hourly and certain employees that joined Occidental from acquired operations with grandfathered benefits, are currently accruing benefits under these plans.
Pension costs for Occidental’s defined benefit pension plans, determined by independent actuarial valuations, are generally funded by payments to trust funds, which are administered by independent trustees.



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 $229 million in 2013, $218 million in 2012 and $194$182 million in 2011.2016, $200 million in 2015 and $215 million in 2014.


67


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):values:
 Pension Benefits Postretirement Benefits
(in millions) Pension Benefits Postretirement Benefits
As of December 31, 2013 2012 2013 2012 2016 2015 2016 2015
Amounts recognized in the consolidated balance sheet:                
Other assets $104
 $24
 $—
 $—
 $61
 $45
 $—
 $—
Accrued liabilities (6) (4) (58) (59) (3) (7) (58) (58)
Deferred credits and other liabilities — other (83) (136) (958) (1,068) (71) (65) (892) (921)
 $15
 $(116) $(1,016) $(1,127) $(13) $(27) $(950) $(979)
AOCI included the following after-tax balances:                
Net loss $66
 $134
 $225
 $324
 $76
 $93
 $169
 $197
Prior service cost 1
 1
 2
 2
 —
 —
 1
 1
 $67
 $135
 $227
 $326
 $76
 $93
 $170
 $198
                
For the years ended December 31,                
Changes in the benefit obligation:                
Benefit obligation — beginning of year $615
 $592
 $1,127
 $1,092
 $411
 $453
 $979
 $1,036
Service cost — benefits earned during the period 13
 13
 29
 25
 7
 7
 20
 26
Interest cost on projected benefit obligation 24
 27
 43
 42
 18
 18
 39
 40
Actuarial (gain) loss (35) 46
 (126) 26
Actuarial gain (1) (16) (28) (66)
Foreign currency exchange rate (gain) loss (5) 2
 —
 —
 1
 (9) —
 —
Benefits paid (54) (57) (57) (58) (37) (42) (60) (57)
Settlements (35) (8) —
 —
Benefit obligation — end of year $523
 $615
 $1,016
 $1,127
 $399
 $411
 $950
 $979
                
Changes in plan assets:                
Fair value of plan assets — beginning of year $499
 $475
 $—
 $—
 $384
 $436
 $—
 $—
Actual return on plan assets 88
 61
 —
 —
 34
 (21) —
 —
Foreign currency exchange rate loss —
 (3) —
 —
Employer contributions 29
 31
 —
 —
 5
 11
 —
 —
Benefits paid (54) (57) —
 —
 (37) (42) —
 —
Settlements (24) (8) —
 —
Fair value of plan assets — end of year $538
 $499
 $—
 $—
 $386
 $384
 $—
 $—
Funded/(Unfunded) status: $15
 $(116) $(1,016) $(1,127) $(13) $(27) $(950) $(979)

The following table sets forth details of the obligations and assets of Occidental's defined benefit pension plans (in millions):plans:
 
Accumulated Benefit
Obligation in Excess of
Plan Assets
 
Plan Assets
in Excess of Accumulated
Benefit Obligation
As of December 31, (in millions) 2013 2012 2013 2012
(in millions) 
Accumulated Benefit
Obligation in Excess of
Plan Assets
 
Plan Assets
in Excess of Accumulated
Benefit Obligation
As of December 31, 2016 2015 2016 2015
Projected Benefit Obligation $122
 $305
 $401
 $310
 $193
 $160
 $206
 $251
Accumulated Benefit Obligation $112
 $278
 $386
 $305
 $189
 $156
 $206
 $251
Fair Value of Plan Assets $39
 $171
 $499
 $328
 $119
 $88
 $267
 $296

Occidental does not expect any plan assets to be returned during 20142017.

68



COMPONENTS OF NET PERIODIC BENEFIT COST

The following table sets forth the components of net periodic benefit costs (in millions):costs:
 Pension Benefits Postretirement Benefits Pension Benefits Postretirement Benefits
For the years ended December 31, (in millions) 2013 2012 2011 2013 2012 2011 2016 2015 2014 2016 2015 2014
Net periodic benefit costs:                        
Service cost — benefits earned during the period $13
 $13
 $12
 $29
 $25
 $22
 $7
 $7
 $11
 $19
 $26
 $24
Interest cost on projected benefit obligation 24
 27
 29
 43
 42
 45
 18
 18
 23
 39
 40
 44
Expected return on plan assets (31) (31) (33) —
 —
 —
 (24) (27) (33) —
 —
 —
Recognized actuarial loss 19
 19
 13
 38
 37
 31
 12
 10
 6
 15
 27
 20
Other costs and adjustments (13) 17
 —
 1
 1
 1
 4
 (4) (8) 1
 1
 1
Net periodic benefit cost $12
 $45
 $21
 $111
 $105
 $99
 $17
 $4

$(1) $74
 $94

$89

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 $6$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 $24$15 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 Pension Benefits Postretirement Benefits
For the years ended December 31, 2013 2012 2013 2012 2016 2015 2016 2015
Benefit Obligation Assumptions:                
Discount rate 4.45% 3.59% 4.75% 3.89% 3.90% 4.14% 4.15% 4.36%
Rate of compensation increase 4.00% 4.00% —
 —
Net Periodic Benefit Cost Assumptions:                
Discount rate 3.59% 4.12% 3.89% 4.12% 4.14% 3.81% 4.36% 3.99%
Assumed long term rate of return on assets 6.50% 6.50% —
 —
 6.50% 6.50% —
 —
Rate of compensation increase 4.00% 4.00% —
 —

For domestic pension plans and postretirement benefit plans, Occidental based the discount rate on the Aon/Hewitt AA-AAA Universe yield curve in 20132016 and 2012. The weighted-average rate of increase in future compensation levels is consistent with Occidental’s past and anticipated future compensation increases for employees participating in retirement plans that determine benefits using compensation.2015. The assumed long-termlong 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 2016, Occidental adopted the Society of Actuaries 2016 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 new mortality improvement scale reflects additional data that the Social Security Administration has released since the 2014 Mortality Tables Report and Mortality Improvement Scale released in 2015. This additional data shows a lower degree of mortality improvement than previously reflected. The changes in the mortality improvement scale results in adecrease of $5 million and $19 million in the pension and postretirement benefit obligation at December 31, 2016.
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 1.0 percent to 10.8 percent at December 31, 2016 and from 1.5 percent to 10.010 percent at both December 31, 2013 and 2012.2015. The average rate of increase in future compensation levels ranged from 1.51.0 percent to 10.0 percent in 2013,2016, depending on local economic conditions. The expected long-term rate of return on plan assets was 6.5 percent in excess of local inflation in both 2013 and 2012.
The postretirement benefit obligation was determined by application of the terms of medical and dental benefits and life insurance coverage, including the effect of established maximums on covered costs, together with relevant actuarial assumptions and healthcare cost trend rates projected at an assumed U.S. Consumer Price Index (CPI) increase of 2.361.97 percent and 2.391.60 percent as of December 31, 20132016 and 2012,2015, 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 8.06.50 percent in 20132016 until they reach 5.04.50 percent in 2025, and remain at 5.04.50 percent thereafter. A 1-percent increase or a 1-percent decrease in these assumed healthcare cost trend rates would result in an increase of $38$44 million or a reduction of $32$36 million, respectively, in the postretirement benefit obligation as of December 31, 2013.2016. 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.


69



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 (Investment Committee) in its role as fiduciary. The Investment Committee, consisting of senior Occidental executives, selects and employs various external professional investment management firms to manage specific investments across the spectrum of asset classes. Equity investments are diversified across United States and non-United States stocks, as well as differing styles and market capitalizations. Other asset classes, such as private equity and real estate, may be used with the goals of enhancing long-term returns and improving portfolio diversification. The target allocation of plan assets is 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):follows:
 Fair Value Measurements at December 31, 2013 Using
(in millions) Fair Value Measurements at December 31, 2016 Using
Description Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Asset Class:                
U.S. government securities $16
 $—
 $—
 $16
 $13
 $—
 $—
 $13
Corporate bonds (a)
 —
 84
 —
 84
 —
 85
 —
 85
Common/collective trusts (b)
 —
 19
 —
 19
 —
 18
 —
 18
Mutual funds:                
Bond funds 64
 —
 —
 64
 18
 —
 —
 18
Blend funds 105
 —
 —
 105
 48
 —
 —
 48
Value and growth funds 6
 —
 —
 6
Common and preferred stocks (c)
 201
 —
 —
 201
 178
 —
 —
 178
Other —
 37
 11
 48
 —
 29
 —
 29
Total pension plan assets (d)
 $392
 $140
 $11
 $543
 $257
 $132
 $—
 $389

 Fair Value Measurements at December 31, 2012 Using
(in millions) Fair Value Measurements at December 31, 2015 Using
Description Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Asset Class:                
U.S. government securities $24
 $—
 $—
 $24
 $16
 $—
 $—
 $16
Corporate bonds (a)
 —
 83
 —
 83
 —
 78
 —
 78
Common/collective trusts (b)
 —
 11
 —
 11
 —
 12
 —
 12
Mutual funds:                
Bond funds 84
 —
 —
 84
 33
 —
 —
 33
Blend funds 106
 —
 —
 106
 48
 —
 —
 48
Value and growth funds 5
 —
 —
 5
Common and preferred stocks (c)
 146
 —
 —
 146
 169
 —
 —
 169
Other —
 35
 11
 46
 —
 29
 —
 29
Total pension plan assets (d)
 $365
 $129
 $11
 $505
 $266
 $119
 $—
 $385
(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 $5$3 million and $6$1 million as of December 31, 20132016 and 20122015, respectively.

The activity during the years ended December 31, 20132016 and 20122015, for the assets using Level 3 fair value measurements was insignificant.
Occidental expects to contribute $6$3 million in cash to its defined benefit pension plans during 2014.2017.


70


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
2014 $46
 $59
2015 $44
 $60
2016 $49
 $61
2017 $41
 $62
2018 $40
 $63
2019 — 2023 $233
 $335
For the years ended December 31, (in millions) 
Pension
Benefits
 Postretirement Benefits
2017 $41
 $59
2018 $30
 $58
2019 $28
 $58
2020 $29
 $57
2021 $29
 $57
2022 - 2026 $185
 $285


NOTE 14INVESTMENTS AND RELATED-PARTY TRANSACTIONS

As of December 31, 2013 and 2012, investments in unconsolidated entities comprised $1.5 billion and $1.9 billion of equity-method investments, respectively.

EQUITY INVESTMENTS
As of December 31, 20132016 and 2015, investments in unconsolidated entities comprised $1.4 billion and $1.3 billion of equity-method investments, respectively.
As of December 31, 2016, Occidental’s equity investments consisted mainly of an approximate 25-percenta 12-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 $447$224 million, $526$438 million, and $349$396 million to Occidental in 2013, 20122016, 2015 and 2011,2014, respectively. As of December 31, 2013,2016, cumulative undistributed earnings of equity-method investees since their respective acquisitions totaled approximately $65 million.they were acquired was immaterial. As of December 31, 2013,2016, Occidental's investments in equity investees exceeded the underlying equity in net assets by approximately $900$653 million, of which almost $750$537 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) 2013 2012 2011 2016 2015 2014
Revenues $3,373
 $2,667
 $2,439
 $1,238
 $1,050
 $3,090
Costs and expenses 2,987
 2,310
 2,046
 1,043
 827
 2,774
Net income $386
 $357
 $393
 $195
 $223
 $316
            
As of December 31, (in millions) 2013 2012   2016 2015  
Current assets $1,813
 $2,242
   $914
 $896
  
Non-current assets $4,412
 $5,449
   $3,605
 $3,589
  
Current liabilities $1,308
 $1,799
   $577
 $536
  
Long-term debt $2,506
 $2,833
   $1,957
 $2,141
  
Other non-current liabilities $163
 $248
   $159
 $149
  
Stockholders’ equity $2,248
 $2,811
   $1,826
 $1,659
  

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


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 71.5 million shares of, or approximately 18.7 percent interest in, California Resources stock, which was recorded as an available for sale investment. Occidental recorded an other-than-temporary loss of $227 million for this available for sale investment as of December 31, 2015. At December 31, 2015, Occidental's available for sale investment in California Resources was $167 million.
71In March 2016, Occidental distributed a special stock dividend for all of its 71.5 million shares of common stock of California Resources to stockholders and recorded a $78 million loss to reduce the investment to its fair market value. Occidental no longer owns any shares of California Resources common stock.


RELATED-PARTY TRANSACTIONS
From time to time, Occidental purchases oil, NGLs, power, steam and chemicals from and sells oil, NGLs, natural gas, chemicals and power to certain of its equity investees and other related parties at market-related prices.parties. During 20132016, 20122015 and 20112014, Occidental entered into the following related-party transactions and had the following amounts due from or to its related parties:
December 31, (in millions) 2013 2012 2011
For the years ended December 31, (in millions) 2016 2015 2014
Sales (a)
 $663
 $419
 $392
 $602
 $555
 $835
Purchases $—
 $8
 $10
 $7
 $26
 $6
Services $30
 $17
 $10
 $17
 $32
 $27
Advances and amounts due from $67
 $25
 $32
 $59
 $60
 $26
Amounts due to $3
 $129
 $21
 $—
 $5
 $15
(a)
In 2013, 20122016, 2015 and 2011,2014, sales of Occidental-produced oil and NGLs to Plains Pipeline accounted for 7289 percent, 8087 percent and 7646 percent of these totals, respectively. Additionally,Sales to Plains Pipeline related to Occidental's oil and gas production are disclosed above. In addition to these sales, Occidental conducts marketing and trading activities with Plains Pipeline for oil, NGLs and NGLs. These transactionstransportation. Net margins associated with these marketing activities are reported in Occidental's income statement on a net margin basis. The sales amounts above include the net margins on such transactions, which were negligible.


NOTE 15FAIR VALUE MEASUREMENTS

FAIR VALUES – RECURRING
In January 2012, Occidental entered into a long-term contract to purchase CO2. This contract contains a price adjustment clause that is linked to changes in NYMEX crude oil prices. Occidental determined that the portion of this contract linked to NYMEX oil prices is not clearly and closely related to the host contract, and Occidental therefore bifurcated this embedded pricing feature from its host contract and accounts for it at fair value in the consolidated financial statements.
The following tables provide fair value measurement information for assets and liabilities that are measured on a recurring basis as of December 31, 2013 and 2012 (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
basis:

  Fair Value Measurements at December 31, 2012 Using Netting and Collateral 
Total
Fair Value
         
Description Level 1 Level 2 Level 3  
Assets:          
Commodity derivatives $107
 $312
 $—
 $(301) $118
Liabilities:          
Commodity derivatives $99
 $398
 $—
 $(371) $126
(in millions) Fair Value Measurements at December 31, 2016 Using Netting and Collateral 
Total
Fair Value
           
Description   Level 1 Level 2 Level 3  
Liabilities:            
Embedded derivative Accrued liabilities $—
 $43
 $—
 $—
 $43
 Deferred credits and liabilities $—
 $178
 $—
 $—
 $178

(in millions) Fair Value Measurements at December 31, 2015 Using Netting and Collateral 
Total
Fair Value
           
Description   Level 1 Level 2 Level 3  
Assets:            
Available for sale investment   $167
 $—
 $—
 $—
 $167
             
Liabilities:            
Embedded derivative Accrued liabilities $—
 $47
 $—
 $—
 $47
 Deferred credits and liabilities $—
 $267
 $—
 $—
 $267


FAIR VALUES – NONRECURRING
During its annual capital planning process in the fourth quarter of 2013, 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,12 months ended December 31, 2016, Occidental recordedrecognized pre-tax impairment charges of $0.6$15 million related to proved oil and gas properties.
As a result of the sharp decline of the forward price curve during 2015, as well as the decision to sell or exit non-core operations, Occidental recognized approximately $6.5 billion for the acreage.
At year end 2012, Occidental performed impairment tests with respect to its proved and unproved properties due to the negative revisions to certain of its natural gas reserves and the continued deterioration of natural gas prices. In the fourth quarter of 2012, Occidental recordedin pre-tax impairment charges related to proved oil and gas properties. Internationally, Occidental recognized $4.7 billion in pre-tax impairment charges related to $1.8 billion in charges in Oman, $1.3 billion in Iraq and Libya, $1 billion in Qatar, and $550 million in Colombia and Bolivia. Domestically, Occidental recognized approximately $763 million pre-tax impairment charges related to the sale of $1.7 billion, almost all of which werethe Williston assets, $460 million pre-tax impairment charges for certain assets in Midcontinent, over 90 percent of which werethe Piceance Basin as well as a $554 million pre-tax impairment charges related to naturalproved oil and gas properties which were acquired more than five years ago on average.in South Texas.

72


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 appropriatea risk adjusted discount rates.rate of 8-20 percent. These properties were impacted by persistently worldwide low oil and natural gas prices in the United Statesand 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 the fourth quarter 2015, Occidental recognized approximately $814 million in pre-tax impairment charges for a Midstream CO2 treatment plant related to recurring CO2 shortfalls and unpaid penalty fees.
In 2015, Occidental recognized approximately $121 million pre-tax charges related to the impairments of Chemical assets.



(in millions) Fair Value Measurements at December 31, 2015 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 - international $—
 $—
 $2,666
 $7,359
 $4,693
Impaired proved oil and gas assets - domestic $—
 $—
 $625
 $1,655
 $1,030
Impaired Midstream assets $—
 $—
 $50
 $891
 $841
Impaired Chemical property, plant, and equipment $—
 $—
 $3
 $124
 $121
           
(in millions) Fair Value Measurements at September 30, 2015 Using 
Net
Book Value (a)
 
Total Pre-tax
(Non-cash) Impairment Loss
         
Description Level 1 Level 2 Level 3  
Williston proved oil and gas assets (b)
 $—
 $—
 $615
 $1,378
 $763
(a)Amount represents net book value at date of assessment.
(b)Williston assets sold in November 2015, classified as held for sale and written down to the sales price at September 30, 2015.

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

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



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 other commodities.capacity. Additionally, the midstream and marketing segment invests in entities that conduct similar activities.
EarningsResults 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.&E.

73


Industry Segments                     
In millions Oil and Gas Chemical 
Midstream and
Marketing
 
Corporate
and
Eliminations
 Total 
(in millions) Oil and Gas Chemical 
Midstream and
Marketing
 
Corporate
and
Eliminations
 Total
 Oil and Gas Chemical 
Midstream and
Marketing
 
Corporate
and
Eliminations
 Total   
YEAR ENDED DECEMBER 31, 2013  
Year ended December 31, 2016          
Net sales $19,132
(a) 
$4,673
(b) 
$1,538
(c) 
$(888) $24,455
  $6,377
(a) 
$3,756
(b) 
$684
(c) 
$(727) $10,090
Pretax operating profit (loss) $7,894
(d) 
$743
(e) 
$1,573
(f) 
$(533)
(g,i) 
$9,677
(d,e,f) 
 $(636)
(d) 
$571
(e) 
$(381)
(f) 
$(1,218)
(g) 
$(1,664)
Income taxes —
 —
 —
 (3,755)
(h,i) 
(3,755)  —
 —
 —
 662
(h) 
662
Discontinued operations, net —
 —
 —
 (19) (19)  —
 —
 —
 428
(i) 
428
Net income (loss) $7,894
 $743
 $1,573
 $(4,307) $5,903
 
Net income (loss) attributable to common stock $(636) $571
 $(381) $(128) $(574)
Investments in unconsolidated entities $108
 $34
 $1,307
 $10
 $1,459
  $—
 $730
 $666
 $5
 $1,401
Property, plant and equipment additions, net (j)
 $7,106
 $435
 $1,482
 $165
 $9,188
 
Property, plant and equipment additions, net (k)
 $1,998
 $353
 $370
 $59
 $2,780
Depreciation, depletion and amortization $4,753
 $346
 $212
 $36
 $5,347
  $3,575
 $340
 $313
 $40
 $4,268
Total assets $46,213
 $3,947
 $14,374
 $4,909
 $69,443
  $24,130
 $4,348
 $11,059
 $3,572
 $43,109
YEAR ENDED DECEMBER 31, 2012           
Year ended December 31, 2015          
Net sales $18,906
(a) 
$4,580
(b) 
$1,399
(c) 
$(713) $24,172
  $8,304
(a) 
$3,945
(b) 
$891
(c) 
$(660) $12,480
Pretax operating profit (loss) $7,095
(d) 
$720
 $439
 $(501)
(g,i) 
$7,753
(d) 
 $(8,060)
(d) 
$542
(e) 
$(1,194)
(f) 
$(764)
(g) 
$(9,476)
Income taxes —
 —
 —
 (3,118)
(h,i) 
(3,118)  —
 —
 —
 1,330
(j) 
1,330
Discontinued operations, net —
 —
 —
 (37) (37)  $—
 —
 —
 317
(i) 
317
Net income (loss) $7,095
 $720
 $439
 $(3,656) $4,598
 
Net income (loss) attributable to common stock $(8,060) $542
 $(1,194) $883
 $(7,829)
Investments in unconsolidated entities $113
 $108
 $1,662
 $11
 $1,894
  $4
 $550
 $708
 $5
 $1,267
Property, plant and equipment additions, net (j)
 $8,282
 $365
 $1,612
 $91
 $10,350
 
Property, plant and equipment additions, net (k)
 $4,485
 $271
 $611
 $42
 $5,409
Depreciation, depletion and amortization $3,933
 $345
 $206
 $27
 $4,511
  $3,886
 $371
 $249
 $38
 $4,544
Total assets $44,004
 $3,854
 $12,762
 $3,590
  
$64,210
  $23,591
 $3,982
 $10,175
 $5,661
  
$43,409
YEAR ENDED DECEMBER 31, 2011           
Year ended December 31, 2014          
Net sales $18,419
(a) 
$4,815
(b) 
$1,447
(c) 
$(742) $23,939
  $13,887
(a) 
$4,817
(b) 
$1,373
(c) 
$(765) $19,312
Pretax operating profit (loss) $10,241
(d) 
$861
 $448
 $(709)
(g,i) 
$10,841
(d) 
 $428
(d) 
$420
(e) 
$2,578
(f) 
$(1,871)
(g) 
$1,555
Net income attributable to noncontrolling interest     (14)   (14)
Income taxes —
 —
 —
 (4,201)
(h,i) 
(4,201)        (1,685)
(h) 
(1,685)
Discontinued operations, net —
 —
 —
 131
 131
  —
 —
 —
 760
(j) 
760
Net income (loss) $10,241
(d) 
$861
 $448
 $(4,779) $6,771
 
Net income (loss) attributable to common stock $428
 $420
 $2,564
 $(2,796) $616
Investments in unconsolidated entities $128
 $121
 $1,812
 $11
 $2,072
  $11
 $202
 $948
 $10
 $1,171
Property, plant and equipment additions, net (j)
 $6,192
 $241
 $1,120
 $51
 $7,604
 
Property, plant and equipment additions, net (l)
 $6,589
 $325
 $2,093
 $103
 $9,110
Depreciation, depletion and amortization $3,064
 $330
 $173
 $24
 $3,591
  $3,701
 $367
 $160
 $33
 $4,261
Total assets $38,967
 $3,754
 $11,962
 $5,361
  
$60,044
  $31,072
 $3,917
 $12,283
 $8,965
  
$56,237
(See footnotes on next page)                    


74



Footnotes:
(a)
Oil sales represented approximately 89 percent, 90 percent and 87 percent of the oil and gas segment net sales for the years ended December 31, 2013, 20122016, 2015 and 2011, respectively.
2014.
(b)Net sales for the chemical segment comprised the following products:
  Basic Chemicals Vinyls Other Chemicals
Year ended December 31, 2013 55% 42% 3%
Year ended December 31, 2012 57% 40% 3%
Year ended December 31, 2011 58% 39% 3%
  Basic Chemicals Vinyls Other Chemicals
Year ended December 31, 2016 57% 40% 3%
Year ended December 31, 2015 56% 40% 4%
Year ended December 31, 2014 54% 43% 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, 2013 51% 36% 13%
Year ended December 31, 2012 59% 27% 14%
Year ended December 31, 2011 64% 35% 1%
  Gas Processing Power 
Marketing,
Transportation and other *
Year ended December 31, 2016 92% 44% (36)%
Year ended December 31, 2015 70% 31% (1)%
Year ended December 31, 2014 49% 31% 20%
* Revenue from all marketing activities is reported on a net basis.

(d)The 20132016 amount includes pre-tax asset sale gains of $121 million and $59 million related to Piceance and South Texas oil and gas properties, pre-tax charges of $61 million related to the sale of Libya and the exit from Iraq, and pre-tax gain of $24 million for other related items. The 2015 amount includes pre-tax charges of $607 million$5 billion for the impairment of domestic non-producing acreage. The 2012 amount includes pre-tax charges of $1.7international oil and gas assets and related items and $3.5 billion for the impairment of domestic oil and gas assets and related items. The 20112014 amount includes pre-tax charges of $35 million related to exploration write-offs in Libya$4.7 billion for the impairment of domestic oil and $29 million related to a Colombian net worth tax,gas assets, pre-tax charges of $1.1 billion for the impairment of foreign oil and agas assets, and pre-tax gain of $531 million for the sale of an interest in a Colombian pipeline of $22 million.  the Hugoton field.
(e)IncludesThe 2016 amount includes gain on sale of $57 million and $31 million related to Occidental Tower in Dallas, Texas and a non-core specialty chemicals business, respectively. The 2015 amount includes the pre-tax charge of $121 million related to asset impairment partially offset by a $98 million gain of $131 million for theon sale of an investment in Carbocloro.idled facility. The 2014 amount includes the pre-tax charge of $149 million related to asset impairment.
(f)Includes a
The 2016 amount includes pre-tax gaincharges of $1,030$160 million related to the termination of crude oil supply contracts. The 2015 amount includes pre-tax charges of $1.3 billion related to asset impairments and related items. The 2014 amount includes pre-tax gains of $633 million and $1,351 million for the salesales of BridgeTex Pipeline and a portion of an investment in Plains Pipeline, respectively, and other items.charges of $31 million.
(g)Includes unallocated net interest expense, administration expense, environmental remediation and other pre-tax items noted in footnote (i)(k) below.
(h)Includes all foreign and domestic income taxes from continuing operations.
(i)Includes discontinued operations from Ecuador.
(j)Includes discontinued operations from Ecuador and California Resources.
(k)Includes the following significant items affecting earnings for the years ended December 31:
Benefit (Charge)  (In millions) 2013 2012 2011
CORPORATE      
Pre-tax operating profit (loss)      
Premium on debt extinguishments $—
 $—
 $(163)
Litigation reserves —
 (20) —
Charge for former executives and consultants (55) —
 —
  $(55) $(20) $(163)
Income taxes      
State income tax charge $—
 $—
 $(33)
Tax effect of pre-tax adjustments * (179) 636
 50
  $(179) $636
 $17
Benefit (Charge)  (in millions) 2016 2015 2014
CORPORATE      
Pre-tax operating profit (loss)      
Asset sale losses $—
 $(8) $—
Asset impairments and related items (619) (235) (1,358)
Severance, spin-off and other —
 (118) (61)
  $(619) $(361) $(1,419)
Income taxes      
Tax effect of pre-tax and other adjustments * $424
 $1,903
 $927
* Amounts represent the tax effect of the pre-tax adjustments listed in this note, as well as those in footnotes (d), (e) and (f).

(j)(l)     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
(in millions) 
Net sales (a)
 Property, plant and equipment, net
For the years ended December 31, 2013 2012 2011 2013 2012 2011 2016 2015 2014 2016 2015 2014
United States $16,009
 $15,359
 $15,040
 $42,956
 $40,786
 $36,283
 $6,290
 $7,479
 $11,943
 $24,004
 $23,265
 $26,673
Foreign                        
Oman 1,101
 1,631
 2,524
 1,858
 1,292
 2,876
Qatar 2,995
 3,356
 3,432
 2,605
 2,676
 2,735
 1,206
 1,449
 2,803
 1,299
 1,354
 2,605
Oman 2,567
 2,578
 2,500
 2,509
 2,353
 2,143
Colombia 1,022
 1,027
 1,054
 1,259
 1,041
 854
 463
 570
 938
 741
 821
 1,396
United Arab Emirates —
 —
 —
 3,131
 2,104
 971
 664
 477
 —
 4,373
 4,484
 4,312
Other Foreign 1,862
 1,852
 1,913
 3,361
 3,104
 2,698
 366
 874
 1,104
 62
 423
 1,868
Total Foreign 8,446
 8,813
 8,899
 12,865
 11,278
 9,401
 3,800
 5,001
 7,369
 8,333
 8,374
 13,057
Total $24,455
 $24,172
 $23,939
 $55,821
 $52,064
 $45,684
 $10,090
 $12,480
 $19,312
 $32,337
 $31,639
 $39,730
(a)Sales are shown by individual country based on the location of the entity making the sale.

75


NOTE 17SPIN-OFF OF CALIFORNIA RESOURCES CORPORATION

On November 30, 2014, Occidental's California oil and gas operations and related assets were spun-off through the pro rata 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.
In connection with the spin-off, California Resources distributed to Occidental $4.95 billion in restricted cash and $1.15 billion in unrestricted cash. The $4.95 billion distribution was used solely to pay dividends, repurchase shares of Occidental stock and repay debt within eighteen months following the distribution.
On March 24, 2016, Occidental distributed all of its remaining 71.5 million shares of common stock of California Resources to stockholders of record as of February 29, 2016 as a special stock dividend.
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
Sales and other operating revenue from discontinued operations $3,951
Income from discontinued operations before-tax 1,205
Income tax expense 440
Income from discontinued operations $765



20132016 Quarterly Financial Data (Unaudited)
Occidental Petroleum Corporation
and Subsidiaries
Inin millions, except per-share amounts


Three months ended March 31 June 30 September 30 December 31  March 31 June 30 September 30 December 31 
Segment net sales                  
Oil and gas $4,440
 $4,721
 $5,018
 $4,953
  $1,275
 $1,625
 $1,660
 $1,817
 
Chemical 1,175
 1,187
 1,200
 1,111
  890
 908
 988
 970
 
Midstream, marketing and other 453
 269
 442
 374
 
Midstream and marketing 133
 141
 202
 208
 
Eliminations (196) (215) (211) (266)  (175) (143) (202) (207) 
Net sales $5,872
 $5,962
 $6,449
 $6,172
  $2,123
 $2,531
 $2,648
 $2,788
 
                  
Gross profit $2,549
 $2,586
 $3,049
 $2,619
  $(335) $143
 $203
 $345
 
                  
Segment earnings                  
Oil and gas $1,920
 $2,100
 $2,363
 $1,511
(a) $(485)(a)$(117) $(51)(a)$17
(a)
Chemical 159
 275
(c)181
 128
  214
(b)88
 117
 152
 
Midstream, marketing and other 215
 48
 212
 1,098
(b)
Midstream and marketing (95) (58) (180)(c)(48) 
 2,294
 2,423
 2,756
 2,737
  (366) (87) (114) 121
 
Unallocated corporate items                  
Interest expense, net (30) (29) (28) (23)  (57) (84) (62) (72) 
Income taxes (844) (901) (1,037) (973)  203
 96
 30
 333
 
Other (61) (166) (103) (93)  (140)(d)(61) (92) (650)(d)
Income from continuing operations 1,359
 1,327
 1,588
 1,648
 
Income (loss) from continuing operations (360) (136) (238) (268) 
Discontinued operations, net (4) (5) (5) (5)  438
(e)(3) (3) (4) 
Net income $1,355
 $1,322
 $1,583
 $1,643
 
Net income (loss) attributable to common stock $78
 $(139) $(241) $(272) 
                  
Basic earnings per common share                  
Income from continuing operations $1.69
 $1.65
 $1.97
 $2.05
 
Income (loss) from continuing operations $(0.47) $(0.18) $(0.31) $(0.35) 
Discontinued operations, net (0.01) (0.01) (0.01) (0.01)  0.57
 —
 (0.01) (0.01) 
Basic earnings per common share $1.68
 $1.64
 $1.96
 $2.04
  $0.10

$(0.18)
$(0.32)
$(0.36) 
                  
Diluted earnings per common share                  
Income from continuing operations $1.69
 $1.64
 $1.97
 $2.05
 
Income (loss) from continuing operations $(0.47) $(0.18) $(0.31) $(0.35) 
Discontinued operations, net (0.01) —
 (0.01) (0.01)  0.57
 —
 (0.01) (0.01) 
Diluted earnings per common share $1.68
 $1.64
 $1.96
 $2.04
  $0.10
 $(0.18) $(0.32) $(0.36) 
                  
Dividends per common share $0.64
 $0.64
 $0.64
 $0.64
  $0.75
 $0.75
 $0.76
 $0.76
 
                  
Market price per common share                  
High $88.74
 $95.57
 $94.50
 $99.42
  $72.19
 $78.31
 $78.48
 $75.60
 
Low $77.21
 $77.91
 $84.91
 $90.13
  $58.24
 $66.94
 $67.83
 $64.37
 
(a)
Includes fourthpre-tax asset sale gains of $48 million in the first quarter related to the sale of domestic oil and gas properties, and $59 million in the third quarter related to the sale of South Texas oil and gas properties. Includes pre-tax charges of $607$25 million in the first quarter, $61 million in the third quarter, $9 million in the fourth quarter and a $24 million gain in the fourth quarter related to the impairment of domestic non-producing acreage.oil and gas asset impairments, related items, and other.
(b)Includes fourthfirst quarter pre-tax asset sale gain of $1,030$57 million from the sale of the Occidental Tower building in Dallas and a portion$31 million gain from the sale of an investment in Plains Pipeline and other items.a non-core specialty chemicals business.
(c)Includes secondthird quarter pre-tax gaincharges of $131$160 million fromrelated to the saletermination of crude oil supply contracts.
(d)Includes first quarter pre-tax charges of $78 million and fourth quarter pre-tax charges of $541 million related to a reserve for doubtful accounts.
(e)Includes the Carbocloro investment.gains related to the Ecuador settlement.




76


20122015 Quarterly Financial Data (Unaudited)
Occidental Petroleum Corporation
and Subsidiaries
Inin millions, except per-share amounts

Three months ended March 31 June 30 September 30 December 31  March 31 June 30 September 30 December 31 
Segment net sales                  
Oil and gas $4,902
 $4,495
 $4,635
 $4,874
  $2,009
 $2,342
 $2,054
 $1,899
 
Chemical 1,148
 1,172
 1,119
 1,141
  1,000
 1,030
 1,008
 907
 
Midstream, marketing and other 393
 262
 389
 355
 
Midstream and marketing 197
 294
 231
 169
 
Eliminations (175) (161) (178) (199)  (117) (197) (177) (169) 
Net sales $6,268
 $5,768
 $5,965
 $6,171
  $3,089
 $3,469
 $3,116
 $2,806
 
                  
Gross profit $3,144
 $2,541
 $2,617
 $2,842
  $396
 $766
 $501
 $126
 
                  
Segment earnings                  
Oil and gas $2,504
 $2,043
 $2,026
 $522
(a) $(266)(a)$355
 $(3,128)(a)$(5,021)(a)
Chemical 184
 194
 162
 180
  139
 136
 272
(b)(5)(b)
Midstream, marketing and other 131
 77
 156
 75
 
Midstream and marketing(c)
 (15) 87
 24
 (1,290)(d)
 2,819
 2,314
 2,344
 777
  (142) 578
 (2,832) (6,316) 
Unallocated corporate items                  
Interest expense, net (28) (25) (34) (30)  (28) (7) (47) (59) 
Income taxes (1,139) (875) (855) (249)  19
 (324) 445
 1,190
 
Other (92) (82) (76) (134)  (64) (67) (172)(d)(320)(e)
Income from continuing operations(c) 1,560
 1,332
 1,379
 364
  (215) 180
 (2,606) (5,505) 
Discontinued operations, net (1) (4) (4) (28)  (3) (4) (3) 327
 
Net income $1,559
 $1,328
 $1,375
 $336
  $(218) $176
 $(2,609) $(5,178) 
                  
Basic earnings per common share                  
Income from continuing operations $1.92
 $1.64
 $1.70
 $0.45
 
Income (loss) from continuing operations $(0.28) $0.23
 $(3.41) $(7.21) 
Discontinued operations, net —
 —
 (0.01) (0.03)  —
 —
 (0.01) 0.43
 
Basic earnings per common share $1.92
 $1.64
 $1.69
 $0.42
  $(0.28) $0.23
 $(3.42) $(6.78) 
                  
Diluted earnings per common share                  
Income from continuing operations $1.92
 $1.64
 $1.70
 $0.45
 
Income (loss) from continuing operations $(0.28) $0.23
 $(3.41) $(7.21) 
Discontinued operations, net —
 —
 (0.01) (0.03)  —
 —
 (0.01) 0.43
 
Diluted earnings per common share $1.92
 $1.64
 $1.69
 $0.42
  $(0.28)
$0.23

$(3.42)
$(6.78) 
                  
Dividends per common share $0.54
 $0.54
 $0.54
 $0.54
  $0.72
 $0.75
 $0.75
 $0.75
 
                  
Market price per common share                  
High $106.68
 $98.24
 $93.60
 $87.39
  $83.74
 $82.06
 $77.76
 $77.37
 
Low $91.85
 $76.59
 $82.25
 $72.43
  $71.70
 $73.35
 $63.60
 $64.89
 
(a)Includes pre-tax charges of $310 million in the first quarter, $3.3 billion in the third quarter and $4.9 billion related to oil and gas asset impairments and related items.
(b)Includes third quarter pre-tax asset sale gain of $98 million related to an idled facility and the fourth quarter includes pre-tax charges of $121 million related to asset impairments.
(c)Includes fourth quarter pre-tax charges of $1.7$1.2 billion for the impairment of domestic gas assetsrelated to asset impairments and related items.
(d)Includes pre-tax charges of $100 million related to severance and other items.
(e)Includes fourth quarter pre-tax charges of an other than temporary loss of $227 million for available for sale investment in California Resources stock.




77



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 natural 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 natural 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 2016, 2015 and 2014 disclosures, the calculated average West Texas Intermediate oil prices were $42.75, $50.28 and $94.99 per barrel, respectively. The calculated average Henry Hub natural gas prices for 2016, 2015 and 2014 were $2.55, $2.66 and $4.42 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.
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 continue to 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.



Oil Reserves                
In millions of barrels (MMbbl)        
in millions of barrels (MMbbl)        
 United Latin Middle East/   United Latin Middle East/  
 States America 
North Africa (a)
 Total States America 
  North Africa (a)
 Total
PROVED DEVELOPED AND UNDEVELOPED RESERVES                
Balance at December 31, 2010 (b)
 1,460
 90
 462
 2,012
Balance at December 31, 2013 1,131
 88
 394
 1,613
Revisions of previous estimates (71) (3) (60) (134) (54) 6
 40
 (8)
Improved recovery 135
 16
 50
 201
 224
 9
 32
 265
Extensions and discoveries 8
 4
 3
 15
 15
 —
 2
 17
Purchases of proved reserves 78
 —
 —
 78
 33
 —
 —
 33
Sales of proved reserves —
 —
 —
 —
Sales of proved reserves (b)
 (9) —
 —
 (9)
Production (84) (11) (69) (164) (67) (11) (63) (141)
Balance at December 31, 2011 1,526
 96
 386
 2,008
Balance at December 31, 2014 1,273
 92
 405
 1,770
Revisions of previous estimates (c)
 (220) (10) 22
 (208)
Improved recovery 81
 8
 12
 101
Extensions and discoveries —
 —
 2
 2
Purchases of proved reserves —
 —
 —
 —
Sales of proved reserves (b)
 (146) —
 (51) (197)
Production (73) (13) (73) (159)
Balance at December 31, 2015 915
 77
 317
 1,309
Revisions of previous estimates (70) 4
 (3) (69) (90) 4
 86
 —
Improved recovery 143
 7
 30
 180
 114
 2
 9
 125
Extensions and discoveries 7
 —
 27
 34
 —
 —
 2
 2
Purchases of proved reserves 54
 —
 —
 54
 90
 —
 —
 90
Sales of proved reserves —
 —
 —
 —
Sales of proved reserves (b)
 —
 —
 (26) (26)
Production (93) (11) (67) (171) (69) (12) (62) (143)
Balance at December 31, 2012 1,567
 96
 373
 2,036
Revisions of previous estimates (44) (5) 12
 (37)
Improved recovery 214
 7
 60
 281
Extensions and discoveries 4
 —
 14
 18
Purchases of proved reserves 25
 —
 —
 25
Sales of proved reserves (4) —
 —
 (4)
Production (97) (10) (65) (172)
Balance at December 31, 2013 1,665
 88
 394
 2,147
Balance at December 31, 2016 960
 71
 326
 1,357
        
PROVED DEVELOPED RESERVES                
December 31, 2010 1,126
 69
 366
 1,561
December 31, 2011 1,146
 69
 317
 1,532
December 31, 2012 1,156
 82
 295
 1,533
December 31, 2013 (c)
 1,187
 76
 281
 1,544
December 31, 2013 822
 76
 281
 1,179
December 31, 2014 819
 86
 316
 1,221
December 31, 2015 673
 77
 278
 1,028
December 31, 2016 (d)
 670
 69
 298
 1,037
PROVED UNDEVELOPED RESERVES                
December 31, 2010 334
 21
 96
 451
December 31, 2011 380
 27
 69
 476
December 31, 2012 411
 14
 78
 503
December 31, 2013 (d)
 478
 12
 113
 603
December 31, 2013 309
 12
 113
 434
December 31, 2014 454
 6
 89
 549
December 31, 2015 242
 —
 39
 281
December 31, 2016 (e)
 290
 2
 28
 320
(a)A substantial majority of the proved reserve amounts relate to PSCs and other similar economic arrangements.
(b)ExcludesSales of proved oil reserves in 2016 were related to the sale of Libya. Sales of proved reserves in 2015 were related to the sale of Williston and exit from Iraq. Sales of proved reserves in 2014 were related to the Argentine operations sold in February 2011 and classified as discontinued operationssale of 166 MMbbl as of December 31, 2010. Hugoton.
(c)Revisions of previous estimates were primarily price and price-related.
(d)Approximately 109 percent of the proved developed reserves at December 31, 20132016 are nonproducing, primarily associated with Permian EOR.
(e)A portion of the majorityproved undeveloped reserves associated with Al Hosn Gas are expected to be developed beyond five years and is tied to an approved long term development project.



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, 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 (a)
 (10) —
 —
 (10)
Production (20) —
 (2) (22)
Balance at December 31, 2014 222
 —
 140
 362
Revisions of previous estimates (b)
 (28) —
 10
 (18)
Improved recovery 12
 —
 1
 13
Extensions and discoveries —
 —
 —
 —
Purchases of proved reserves —
 —
 —
 —
Sales of proved reserves —
 —
 —
 —
Production (20) —
 (7) (27)
Balance at December 31, 2015 186
 —
 144
 330
Revisions of previous estimates 1
 —
 70
 71
Improved recovery 28
 —
 —
 28
Extensions and discoveries —
 —
 —
 —
Purchases of proved reserves 26
 —
 —
 26
Sales of proved reserves (3) —
 (2) (5)
Production (19) —
 (11) (30)
Balance, December 31, 2016 219
 —
 201
 420
         
PROVED DEVELOPED RESERVES        
December 31, 2013 151
 —
 51
 202
December 31, 2014 147
 —
 109
 256
December 31, 2015 141
 —
 112
 253
December 31, 2016  (c)
 149
 —
 164
 313
PROVED UNDEVELOPED RESERVES        
December 31, 2013 53
 —
 83
 136
December 31, 2014 75
 —
 31
 106
December 31, 2015 45
 —
 32
 77
December 31, 2016  (d)
 70
 —
 37
 107
(a)Sales of whichproved reserves in 2014 were related to the sale of Hugoton.
(b)Revisions of previous estimates were primarily price and price-related.
(c)Approximately 5 percent of the proved developed reserves at December 31, 2016 are located in the United States.nonproducing, primarily associated with Permian EOR.
(d)The amountA portion of Occidental'sthe proved undeveloped reserves thatassociated with Al Hosn Gas are not expected to be developed withinbeyond five years from the date initially recorded was insignificant. A substantial portion of the Middle East/North Africa proved undeveloped reserves at December 31, 2013, was from the Al Hosn gas project in the United Arab Emirates. Occidental expectsand is tied to transfer a substantial portion of these reserves to the proved developed category at the end of 2014 when additional wells are drilled and initial production begins in the fourth quarter.an approved long term development project.


78


NGL Reserves        
In millions of barrels (MMbbl)        
Natural Gas Reserves    
in billions of cubic feet (Bcf)    
 United Latin Middle East/   United Latin Middle East/  
 States America 
North Africa (a)
 Total States America 
  North Africa (a)
 Total
PROVED DEVELOPED AND UNDEVELOPED RESERVES                
Balance at December 31, 2010 237
 —
 61
 298
Balance, December 31, 2013 2,012
 24
 2,687
 4,723
Revisions of previous estimates —
 —
 (2) (2) (111) 3
 (273) (381)
Improved recovery 10
 —
 —
 10
 284
 4
 25
 313
Extensions and discoveries 1
 —
 —
 1
 27
 —
 101
 128
Purchases of proved reserves 2
 —
 —
 2
 46
 —
 —
 46
Sales of proved reserves —
 —
 —
 —
Sales of proved reserves (b)
 (371) —
 —
 (371)
Production (25) —
 (4) (29) (173) (4) (154) (331)
Balance at December 31, 2011 225
 —
 55
 280
Balance at December 31, 2014 1,714
 27
 2,386
 4,127
Revisions of previous estimates (c)
 (600) (4) 64
 (540)
Improved recovery 123
 —
 64
 187
Extensions and discoveries —
 —
 17
 17
Purchases of proved reserves —
 —
 —
 —
Sales of proved reserves (b)
 (63) —
 —
 (63)
Production (155) (4) (201) (360)
Balance at December 31, 2015 1,019
 19
 2,330
 3,368
Revisions of previous estimates 1
 —
 —
 1
 (19) (10) 554
 525
Improved recovery 16
 —
 —
 16
 138
 —
 51
 189
Extensions and discoveries —
 —
 64
 64
 —
 —
 2
 2
Purchases of proved reserves 1
 —
 —
 1
 128
 —
 —
 128
Sales of proved reserves —
 —
 —
 —
Sales of proved reserves (b)
 (89) —
 —
 (89)
Production (27) —
 (3) (30) (132) (3) (214) (349)
Balance at December 31, 2012 216
 —
 116
 332
Revisions of previous estimates 66
 —
 (1) 65
Improved recovery 13
 —
 —
 13
Extensions and discoveries —
 —
 22
 22
Purchases of proved reserves 7
 —
 —
 7
Sales of proved reserves —
 —
 —
 —
Production (28) —
 (3) (31)
Balance at December 31, 2013 274
 —
 134
 408
Balance at December 31, 2016 1,045
 6
 2,723
 3,774
        
PROVED DEVELOPED RESERVES                
December 31, 2010 163
 —
 61
 224
December 31, 2011 165
 —
 55
 220
December 31, 2012 167
 —
 53
 220
December 31, 2013 (b)
 200
 —
 51
 251
December 31, 2013 1,495
 23
 1,684
 3,202
December 31, 2014 1,128
 26
 1,915
 3,069
December 31, 2015 813
 19
 1,872
 2,704
December 31, 2016 (d)
 708
 6
 2,324
 3,038
PROVED UNDEVELOPED RESERVES                
December 31, 2010 74
 —
 —
 74
December 31, 2011 60
 —
 —
 60
December 31, 2012 49
 —
 63
 112
December 31, 2013 (c)
 74
 —
 83
 157
December 31, 2013 517
 1
 1,003
 1,521
December 31, 2014 586
 1
 471
 1,058
December 31, 2015 206
 —
 458
 664
December 31, 2016 (e)
 337
 —
 399
 736
(a)A substantial portionOver half of proved reserve amounts relate to PSCs and other similar economic arrangements.
(b)2016 sales of proved reserves are related to Piceance. Sales of proved reserves in 2015 were related to the sale of Williston. Sales of proved reserves in 2014 were related to the sale of Hugoton.
(c)Revisions of previous estimates were primarily price and price-related.
(d)Approximately 83 percent of the proved developed reserves at December 31, 20132016 are nonproducing, primarily associated with the majority of which are located in the United States.Permian.
(c)(e)The amountA portion of Occidental'sthe proved undeveloped reserves thatassociated with Al Hosn Gas are not expected to be developed withinbeyond five years from the date initially recorded was insignificant. The Middle East/North Africa proved undeveloped reserves at December 31, 2013, were from the Al Hosn gas project in the United Arab Emirates. Occidental expectsand is tied to transfer a substantial portion of these reserves to the proved developed category at the end of 2014 when additional wells are drilled and initial production begins in the fourth quarter.


79


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, 2010 (b)
 3,034
 56
 2,048
 5,138
Revisions of previous estimates (369) (19) (78) (466)
Improved recovery 222
 2
 95
 319
Extensions and discoveries 35
 —
 16
 51
Purchases of proved reserves 728
 —
 —
 728
Sales of proved reserves —
 —
 —
 —
Production (285) (6) (156) (447)
Balance at December 31, 2011 3,365
 33
 1,925
 5,323
Revisions of previous estimates (748) —
 62
 (686)
Improved recovery 317
 11
 34
 362
Extensions and discoveries 19
 —
 784
 803
Purchases of proved reserves 236
 —
 —
 236
Sales of proved reserves —
 —
 —
 —
Production (300) (5) (165) (470)
Balance at December 31, 2012 2,889
 39
 2,640
 5,568
Revisions of previous estimates (94) (11) (43) (148)
Improved recovery 303
 1
 16
 320
Extensions and discoveries 14
 —
 232
 246
Purchases of proved reserves 34
 —
 —
 34
Sales of proved reserves (2) —
 —
 (2)
Production (289) (5) (158) (452)
Balance at December 31, 2013 2,855
 24
 2,687
 5,566
PROVED DEVELOPED RESERVES        
December 31, 2010 2,007
 50
 1,665
 3,722
December 31, 2011 2,365
 32
 1,555
 3,952
December 31, 2012 2,121
 36
 1,816
 3,973
December 31, 2013 (c)
 2,105
 23
 1,684
 3,812
PROVED UNDEVELOPED RESERVES        
December 31, 2010 1,027
 6
 383
 1,416
December 31, 2011 1,000
 1
 370
 1,371
December 31, 2012 768
 3
 824
 1,595
December 31, 2013 (d)
 750
 1
 1,003
 1,754
(a)A substantial majority of proved reserve amounts relate to PSCs and other similar economic arrangements.
(b)Excludes proved natural gas reserves from the Argentine operations sold in February 2011 and classified as discontinued operations of 182 Bcf as of December 31, 2010.
(c)Approximately 4 percent of the proved developed reserves at December 31, 2013 are nonproducing, the majority of which are located in the United States.
(d)The amount of Occidental's proved undeveloped reserves that are not expected to be developed within five years from the date initially recorded was insignificant. The Middle East/North Africa proved undeveloped reserves at December 31, 2013, were from the Al Hosn gas project in the United Arab Emirates. Occidental expects to transfer a substantial portion of these reserves to the proved developed category at the end of 2014 when additional wells are drilled and initial production begins in the fourth quarter.an approved long term development project.



80



Total Reserves                
In millions of BOE (MMBOE) (a)
        
in millions of BOE (MMBOE) (a)
        
 United Latin Middle East/   United Latin Middle East/  
 States America North Africa 
Total (b)
 States America North Africa 
Total (b)
PROVED DEVELOPED AND UNDEVELOPED RESERVES                
Balance at December 31, 2010 (c)
 2,203
 100
 864
 3,167
Balance at December 31, 2013 1,670
 92
 976
 2,738
Revisions of previous estimates (132) (7) (75) (214) (67) 6
 3
 (58)
Improved recovery 182
 16
 66
 264
 310
 9
 35
 354
Extensions and discoveries 15
 4
 6
 25
 22
 —
 19
 41
Purchases of proved reserves 201
 —
 —
 201
 43
 —
 —
 43
Sales of proved reserves —
 —
 —
 —
Sales of proved reserves (c)
 (81) —
 —
 (81)
Production (156) (12) (99) (267) (116) (11) (91) (218)
Balance at December 31, 2011 2,313
 101
 762
 3,176
Balance at December 31, 2014 1,781
 96
 942
 2,819
Revisions of previous estimates (194) 4
 7
 (183) (348) (10) 43
 (315)
Improved recovery 212
 9
 36
 257
 113
 8
 23
 144
Extensions and discoveries 10
 —
 222
 232
 —
 —
 5
 5
Purchases of proved reserves 94
 —
 —
 94
 —
 —
 —
 —
Sales of proved reserves —
 —
 —
 —
Sales of proved reserves (c)
 (156) —
 (51) (207)
Production (170) (12) (98) (280) (119) (14) (113) (246)
Balance at December 31, 2012 2,265
 102
 929
 3,296
Revisions of previous estimates 7
 (7) 4
 4
Balance at December 31, 2015 1,271
 80
 849
 2,200
Revisions of previous estimates (d)
 (92) 3
 248
 159
Improved recovery 277
 8
 63
 348
 165
 2
 18
 185
Extensions and discoveries 7
 —
 74
 81
 —
 —
 2
 2
Purchases of proved reserves 37
 —
 —
 37
 137
 —
 —
 137
Sales of proved reserves (5) —
 —
 (5)
Sales of proved reserves (c)
 (18) —
 (28) (46)
Production (173) (11) (94) (278) (110) (13) (108) (231)
Balance at December 31, 2013 2,415
 92
 976
 3,483
Balance at December 31, 2016 1,353

72

981

2,406
        
PROVED DEVELOPED RESERVES                
December 31, 2010 1,624
 78
 705
 2,407
December 31, 2011 1,707
 74
 631
 2,412
December 31, 2012 1,677
 88
 651
 2,416
December 31, 2013 (d)
 1,738
 80
 613
 2,431
December 31, 2013 1,222
 80
 613
 1,915
December 31, 2014 1,154
 90
 744
 1,988
December 31, 2015 950
 80
 702
 1,732
December 31, 2016 (e)
 937
 70
 849
 1,856
PROVED UNDEVELOPED RESERVES                
December 31, 2010 579
 22
 159
 760
December 31, 2011 606
 27
 131
 764
December 31, 2012 588
 14
 278
 880
December 31, 2013 (e)
 677
 12
 363
 1,052
December 31, 2013 448
 12
 363
 823
December 31, 2014 627
 6
 198
 831
December 31, 2015 321
 —
 147
 468
December 31, 2016 (f)
 416
 2
 132
 550
(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 2013,2016, the average prices of West Texas Intermediate (WTI) oil and New York Mercantile Exchange (NYMEX) natural gas were $97.97$43.32 per barrel and $3.66$2.42 per Mcf, respectively, resulting in an oil to gas ratio of over 25.18 to 1.
(b)Includes proved reserves related to production-sharing contracts (PSCs)PSCs and other similar economic arrangements of 0.90.5 billion BOE, 0.90.5 billion BOE, 1.00.7 billion BOE and 1.10.8 billion BOE, at December 31, 2013, 2012, 20112016, 2015, 2014, and 2010,2013, respectively.
(c)Excludes2016 sales of proved reserves are related to Libya and Piceance. Sales of proved reserves in 2015 were related to the sale of Williston and exit from Iraq. Sales of proved reserves in 2014 were related to the Argentine operations sold in February 2011 and classified as discontinued operationssale of 196 MMBOE as of December 31, 2010.Hugoton.
(d)Revisions are primarily positive technical revisions in Al Hosn Gas and price revisions in Oman due to the PSC impact, partially offset by negative domestic price revisions.
(e)Approximately 87 percent of the proved developed reserves at December 31, 20132016 are nonproducing, the majority of which are located in the United States.primarily associated with Permian EOR.
(e)(f)The amountA portion of Occidental'sthe proved undeveloped reserves thatassociated with Al Hosn Gas are not expected to be developed withinbeyond five years from the date initially recorded was insignificant. A substantial majority of Middle East/North Africa proved undeveloped reserves at December 31, 2013, was from the Al Hosn gas project in the United Arab Emirates. Occidental expectsand is tied to transfer a substantial portion of these reserves to the proved developed category at the end of 2014 when additional wells are drilled and initial production begins in the fourth quarter.an approved long term development project.


,

81



CAPITALIZED COSTS
Capitalized costs relating to oil and gas producing activities and related accumulated DD&A were as follows:
 United Latin Middle East/   United Latin Middle East/  
In millions States America North Africa Total
December 31, 2013        
in millions States America North Africa Total
December 31, 2016        
Proved properties $48,172
 $2,485
 $18,090
 $68,747
 $32,220
 $3,029
 $16,792
 $52,041
Unproved properties 3,403
 27
 190
 3,620
 2,548
 28
 54
 2,630
Total capitalized costs (a)
 51,575
 2,512
 18,280
 72,367
 34,768
 3,057
 16,846
 54,671
Accumulated depreciation, depletion and amortization (16,388) (1,175) (10,261) (27,824)
Proved properties depreciation, depletion and amortization (15,085) (2,285) (13,067) (30,437)
Unproved properties valuation (1,178) (27) —
 (1,205)
Total Accumulated depreciation, depletion and amortization (16,263) (2,312) (13,067) (31,642)
Net capitalized costs $35,187
 $1,337
 $8,019
 $44,543
 $18,505
 $745
 $3,779
 $23,029
December 31, 2012        
December 31, 2015        
Proved properties $42,563
 $2,142
 $15,873
 $60,578
 $30,200
 $2,955
 $19,290
 $52,445
Unproved properties 4,592
 27
 220
 4,839
 1,376
 27
 1,077
 2,480
Total capitalized costs (a)
 47,155
 2,169
 16,093
 65,417
 31,576
 2,982
 20,367
 54,925
Accumulated depreciation, depletion and amortization (13,432) (1,068) (8,582) (23,082)
Proved properties depreciation, depletion and amortization (12,544) (2,119) (15,718) (30,381)
Unproved properties valuation (1,204) (27) (961) (2,192)
Total Accumulated depreciation, depletion and amortization (13,748) (2,146) (16,679) (32,573)
Net capitalized costs $33,723
 $1,101
 $7,511
 $42,335
 $17,828
 $836
 $3,688
 $22,352
December 31, 2011        
December 31, 2014        
Proved properties $36,123
 $1,861
 $13,839
 $51,823
 $33,186
 $2,788
 $19,545
 $55,519
Unproved properties 4,675
 —
 184
 4,859
 2,389
 27
 1,026
 3,442
Total capitalized costs (a)
 40,798
 1,861
 14,023
 56,682
 35,575
 2,815
 20,571
 58,961
Accumulated depreciation, depletion and amortization (11,063) (951) (7,178) (19,192)
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 $29,735
 $910
 $6,845
 $37,490
 $20,331
 $1,423
 $7,946
 $29,700
(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/   United Latin Middle East/  
In millions States America North Africa Total
FOR THE YEAR ENDED DECEMBER 31, 2013        
in millions States America North Africa Total
FOR THE YEAR ENDED DECEMBER 31, 2016        
Property acquisition costs                
Proved properties $363
 $—
 $—
 $363
 $797
 $—
 $367
 $1,164
Unproved properties 184
 —
 —
 184
 1,265
 —
 —
 1,265
Exploration costs 425
 11
 79
 515
 13
 6
 52
 71
Development costs 4,203
 329
 2,117
 6,649
 1,417
 75
 670
 2,162
Costs incurred $5,175
 $340
 $2,196
 $7,711
 $3,492
 $81
 $1,089
 $4,662
FOR THE YEAR ENDED DECEMBER 31, 2012        
FOR THE YEAR ENDED DECEMBER 31, 2015        
Property acquisition costs                
Proved properties $1,689
 $—
 $14
 $1,703
 $37
 $—
 $47
 $84
Unproved properties 613
 —
 —
 613
 25
 —
 —
 25
Exploration costs 539
 1
 114
 654
 74
 2
 66
 142
Development costs 5,344
 304
 2,025
 7,673
 2,880
 170
 1,461
 4,511
Costs incurred $8,185
 $305
 $2,153
 $10,643
 $3,016
 $172
 $1,574
 $4,762
FOR THE YEAR ENDED DECEMBER 31, 2011        
FOR THE YEAR ENDED DECEMBER 31, 2014        
Property acquisition costs                
Proved properties $3,185
 $—
 $—
 $3,185
 $771
 $—
 $—
 $771
Unproved properties 1,311
 —
 32
 1,343
 842
 —
 —
 842
Exploration costs 400
 33
 87
 520
 379
 4
 180
 563
Development costs 4,100
 214
 1,495
 5,809
 3,665
 305
 2,138
 6,108
Costs incurred $8,996
 $247
  
$1,614
 $10,857
 $5,657
 $309
 $2,318
 $8,284


82




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/   United Latin Middle East/  
In millions States America North Africa Total
FOR THE YEAR ENDED DECEMBER 31, 2013        
Revenues (a)
 $11,152
 $1,075
 $6,949
 $19,176
Production costs (b)
 2,496
 158
 1,172
 3,826
Other operating expenses 827
 21
 278
 1,126
Depreciation, depletion and amortization 2,967
 107
 1,679
 4,753
Taxes other than on income 693
 21
 —
 714
Asset impairments and related items 607
 —
 —
 607
Exploration expenses 184
 6
 66
 256
Pretax income 3,378
 762
 3,754
 7,894
Income tax expense (c)
 1,102
 256
 1,805
 3,163
Results of operations $2,276
 $506
 $1,949
 $4,731
FOR THE YEAR ENDED DECEMBER 31, 2012        
Revenues (a)
 $10,379
 $1,085
 $7,486
 $18,950
Production costs (b)
 2,963
 165
 1,061
 4,189
Other operating expenses 723
 43
 224
 990
Depreciation, depletion and amortization 2,412
 117
 1,404
 3,933
Taxes other than on income 644
 23
 —
 667
Asset impairments and related items 1,731
 —
 —
 1,731
Exploration expenses 230
 3
 112
 345
Pretax income 1,676
 734
 4,685
 7,095
Income tax expense (c)
 508
 252
 2,159
 2,919
Results of operations $1,168
 $482
 $2,526
 $4,176
FOR THE YEAR ENDED DECEMBER 31, 2011 
 
 
 
in millions States America North Africa Total
FOR THE YEAR ENDED DECEMBER 31, 2016        
Revenues (a)
 $9,933
 $1,113
  
$7,373
 $18,419
 $3,135
 $476
 $2,766
 $6,377
Production costs (b)
 2,338
 172
 918
 3,428
 1,335
 170
 982
 2,487
Other operating expenses 584
 37
 217
 838
 426
 36
 218
 680
Depreciation, depletion and amortization 1,754
 90
 1,220
 3,064
 2,793
 156
 626
 3,575
Taxes other than on income 567
 23
 —
 590
 240
 10
 —
 250
Exploration expenses 200
 2
 56
 258
 8
 5
 49
 62
Pretax income 4,490
 789
 4,962
 10,241
Income tax expense (c)
 1,419
 270
 2,145
 3,834
Pretax income (loss) before impairments and related items (1,667)
99

891

(677)
Asset impairments and related items 1
 9
 61
 71
Pretax income (loss) (1,668)
90

830

(748)
Income tax expense (benefit) (c)
 (784) 65
 336
 (383)
Results of operations $3,071
 $519
 $2,817
 $6,407
 $(884) $25
 $494
 $(365)
FOR THE YEAR ENDED DECEMBER 31, 2015        
Revenues (a)
 $3,809
 $589
 $3,906
 $8,304
Production costs (b)
 1,571
 160
 1,113
 2,844
Other operating expenses 511
 29
 238
 778
Depreciation, depletion and amortization 2,109
 196
 1,581
 3,886
Taxes other than on income 307
 16
 —
 323
Exploration expenses 18
 2
 16
 36
Pretax income (loss) before impairments and related items (707)
186

958

437
Asset impairments and related items 3,447
 559
 4,491
 8,497
Pretax income (loss) (4,154)
(373)
(3,533)
(8,060)
Income tax expense (benefit) (c)
 (1,606) (61) 787
 (880)
Results of operations $(2,548)
$(312) $(4,320)
$(7,180)
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 (benefit) (c)
 (1,182) 223
 1,730
 771
Results of operations $(1,785) $334
 $577
 $(874)
(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 and 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.




83


RESULTS PER UNIT OF PRODUCTION FOR CONTINUING OPERATIONS

 United Latin Middle East/   United Latin Middle East/  
 States America North Africa Total
FOR THE YEAR ENDED DECEMBER 31, 2013        
Revenue from each barrel of oil equivalent ($/bbl.) (a,b)
 $64.48
 $100.46
 $73.68
 $68.99
Production costs 14.43
 14.76
 12.43
 13.76
Other operating expenses 4.78
 1.96
 2.95
 4.05
Depreciation, depletion and amortization 17.15
 10.00
 17.80
 17.10
Taxes other than on income 4.01
 1.96
 —
 2.57
Asset impairments and related items 3.51
 —
 —
 2.18
Exploration expenses 1.06
 0.56
 0.70
 0.92
Pretax income 19.54
 71.22
 39.80
 28.41
Income tax expense (c)
 6.37
 23.92
 19.14
 11.38
Results of operations $13.17
 $47.30
 $20.66
 $17.03
FOR THE YEAR ENDED DECEMBER 31, 2012        
Revenue from each barrel of oil equivalent ($/bbl.) (a,b)
 $61.06
 $96.30
 $76.22
 $67.81
Production costs 17.43
 14.64
 10.80
 14.99
Other operating expenses 4.25
 3.82
 2.28
 3.54
Depreciation, depletion and amortization 14.19
 10.38
 14.30
 14.07
Taxes other than on income 3.79
 2.04
 —
 2.39
Asset impairments and related items 10.18
 —
 —
 6.19
Exploration expenses 1.35
 0.27
 1.14
 1.23
Pretax income 9.87
 65.15
 47.70
 25.40
Income tax expense (c)
 2.99
 22.37
 21.98
 10.45
Results of operations $6.88
 $42.78
 $25.72
 $14.95
FOR THE YEAR ENDED DECEMBER 31, 2011 
 
 
 
Revenue from each barrel of oil equivalent ($/bbl.) (a,b)
 $63.56
 $94.19
 $74.58
 $68.99
$/BOE (a)
 States America North Africa Total
FOR THE YEAR ENDED DECEMBER 31, 2016        
Revenues (b)
 $28.36
 $36.87
 $25.67
 $27.59
Production costs 14.96
 14.56
 9.29
 12.84
 12.07
 13.16
 9.12
 10.76
Other operating expenses 3.74
 3.13
 2.20
 3.14
 3.86
 2.76
 2.02
 2.94
Depreciation, depletion and amortization 11.22
 7.62
 12.34
 11.48
 25.27
 12.12
 5.81
 15.46
Taxes other than on income 3.63
 1.95
 —
 2.21
 2.17
 0.77
 —
 1.08
Exploration expenses 1.28
 0.17
 0.57
 0.97
 0.07
 0.39
 0.45
 0.27
Pretax income 28.73
 66.76
 50.18
 38.35
Income tax expense (c)
 9.08
 22.85
 21.70
 14.36
Pretax income (loss) before impairments and related items (15.08)
7.67

8.27

(2.92)
Asset impairments and related items 0.01
 0.70
 0.57
 0.31
Pretax income (loss) (15.09)
6.97

7.70

(3.23)
Income tax expense (benefit) (c)
 (7.09) 5.03
 3.12
 (1.66)
Results of operations $19.65
 $43.91
 $28.48
 $23.99
 $(8.00) $1.94
 $4.58
 $(1.57)
FOR THE YEAR ENDED DECEMBER 31, 2015        
Revenues (b)
 $31.84
 $43.83
 $34.64
 $33.78
Production costs 13.13
 11.93
 9.87
 11.57
Other operating expenses 4.27
 2.18
 2.11
 3.15
Depreciation, depletion and amortization 17.63
 14.54
 14.02
 15.81
Taxes other than on income 2.57
 1.19
 —
 1.32
Exploration expenses 0.15
 0.15
 0.14
 0.15
Pretax income (loss) before impairments and related items (5.91) 13.84
 8.50
 1.78
Asset impairments and related items 28.81
 41.60
 39.82
 34.56
Pretax income (loss) (34.72)
(27.76)
(31.32)
(32.78)
Income tax expense (benefit) (c)
 (13.42) (4.54) 6.98
 (3.58)
Results of operations $(21.30) $(23.22) $(38.30) $(29.20)
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 (benefit) (c)
 (10.21) 19.59
 19.02
 3.54
Results of operations $(15.42) $29.33
 $6.34
 $(4.02)
(a)Natural gas volumes have been converted to BOEbarrels 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 2013,2016, the average prices of WTIWest Texas Intermediate (WTI) oil and NYMEXNew York Mercantile Exchange (NYMEX) natural gas were $97.97$43.32 per barrel and $3.66$2.42 per Mcf, respectively, resulting in an oil to gas ratio of over 25.18 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.


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, 20132016, 20122015 and 20112014, 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.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-percent10 percent discount factor. The calculations assumed the continuation of existing economic, operating and contractual conditions at December 31, 20132016, 20122015 and 20112014. 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.

84


Standardized Measure of Discounted Future Net Cash Flows
In millions        
in millions        
 United Latin Middle East/   United Latin Middle East/  
 States America North Africa Total States America North Africa Total
AT DECEMBER 31, 2013        
AT DECEMBER 31, 2016        
Future cash inflows $174,965
 $9,076
 $50,517
 $234,558
 $42,289
 $2,551
 $21,079
 $65,919
Future costs                
Production costs and other operating expenses (73,092) (3,375) (13,043) (89,510) (23,574) (1,418) (8,101) (33,093)
Development costs (a)
 (18,365) (477) (7,084) (25,926) (7,204) (134) (1,900) (9,238)
Future income tax expense (24,014) (1,571) (13,182) (38,767) —
 (244) (2,349) (2,593)
Future net cash flows 59,494
 3,653
 17,208
 80,355
 11,511
 755
 8,729
 20,995
Ten percent discount factor (32,035) (1,557) (6,597) (40,189) (6,676) (202) (4,404) (11,282)
Standardized measure of discounted future net cash flows $27,459
 $2,096
 $10,611
 $40,166
 $4,835
 $553
 $4,325
 $9,713
AT DECEMBER 31, 2012        
AT DECEMBER 31, 2015        
Future cash inflows $161,821
 $10,574
 $48,914
 $221,309
 $47,290
 $3,416
 $22,994
 $73,700
Future costs                
Production costs and other operating expenses (68,780) (3,562) (11,922) (84,264) (25,386) (1,852) (9,041) (36,279)
Development costs (a)
 (15,890) (541) (5,539) (21,970) (7,245) (178) (2,672) (10,095)
Future income tax expense (21,387) (2,023) (14,165) (37,575) (759) (392) (4,045) (5,196)
Future net cash flows 55,764
 4,448
 17,288
 77,500
 13,900
 994
 7,236
 22,130
Ten percent discount factor (29,745) (1,812) (6,656) (38,213) (7,446) (293) (2,996) (10,735)
Standardized measure of discounted future net cash flows $26,019
 $2,636
 $10,632
 $39,287
 $6,454
 $701
 $4,240
 $11,395
AT DECEMBER 31, 2011        
AT DECEMBER 31, 2014        
Future cash inflows $171,456
 $8,494
 $43,715
 $223,665
 $122,377
 $8,325
 $48,684
 $179,386
Future costs                
Production costs and other operating expenses (69,404) (2,807) (8,926) (81,137) (48,436) (3,422) (13,020) (64,878)
Development costs (a)
 (13,660) (689) (3,407) (17,756) (16,618) (397) (7,245) (24,260)
Future income tax expense (26,175) (1,579) (15,374) (43,128) (15,939) (1,322) (11,211) (28,472)
Future net cash flows 62,217
 3,419
 16,008
 81,644
 41,384
 3,184
 17,208
 61,776
Ten percent discount factor (32,835) (1,415) (5,127) (39,377) (23,722) (1,219) (6,686) (31,627)
Standardized measure of discounted future net cash flows $29,382
 $2,004
 $10,881
 $42,267
 $17,662
 $1,965
 $10,522
 $30,149
(a)Includes asset retirement costs.



Changes in the Standardized Measure of Discounted Future            
Net Cash Flows From Proved Reserve Quantities            
In millions      
in millions      
For the years ended December 31, 2013 2012 2011 2016 2015 2014
Beginning of year $39,287
 $42,267
 $32,737
 $11,395
 $30,149
 $30,412
Sales and transfers of oil and gas produced, net of production costs and other operating expenses (15,406) (14,818) (15,243) (3,830) (4,952) (11,016)
Net change in prices received per barrel, net of production costs and other operating expenses 2,575
 (3,005) 20,325
 (3,714) (36,081) (3,641)
Extensions, discoveries and improved recovery, net of future production and development costs 6,706
 5,625
 6,152
 811
 854
 4,754
Change in estimated future development costs (4,592) (7,330) (5,668) (227) 3,091
 (3,375)
Revisions of quantity estimates (537) (2,057) (3,518) 868
 (1,782) 190
Development costs incurred during the period 6,669
 7,700
 5,797
Previously estimated development costs incurred during the period 1,662
 3,327
 4,676
Accretion of discount 4,617
 5,203
 4,014
 1,034
 3,220
 3,456
Net change in income taxes 2,087
 5,045
 (4,776) 1,367
 13,046
 3,673
Purchases and sales of reserves in place, net 522
 1,076
 3,220
 178
 (2,334) 45
Changes in production rates and other (1,762) (419) (773) 169
 2,857
 975
Net change 879
 (2,980) 9,530
 (1,682) (18,754) (263)
End of year $40,166
 $39,287
 $42,267
 $9,713
 $11,395
 $30,149

85


Average Sales Prices
The following table sets forth, for each of the three years in the period ended December 31, 20132016, Occidental’s approximate average sales prices in continuing operations.
 United Latin Middle East/   United Latin Middle East/  
  States 
America (a)
 North Africa Total  States America North Africa Total
2013            
2016            
Oil — Average sales price ($/bbl) $96.42
 $103.21
 $104.48
 $99.84
 — Average sales price ($/bbl) $39.38
 $37.48
 $38.25
 $38.73
NGLs — Average sales price ($/bbl) $41.80
 $—
 $33.00
 $41.03
 — Average sales price ($/bbl) $14.72
 $—
 $15.01
 $14.82
Gas — Average sales price ($/mcf) $3.37
 $11.17
 $0.76
 $2.54
 — Average sales price ($/mcf) $1.90
 $3.78
 $1.27
 $1.53
2012            
2015            
Oil — Average sales price ($/bbl) $93.72
 $98.35
 $108.76
 $99.87
 — Average sales price ($/bbl) $45.04
 $44.49
 $49.65
 $47.10
NGLs — Average sales price ($/bbl) $46.07
 $—
 $37.74
 $45.18
 — Average sales price ($/bbl) $15.35
 $—
 $17.88
 $15.96
Gas — Average sales price ($/mcf) $2.62
 $11.85
 $0.76
 $2.06
 — Average sales price ($/mcf) $2.15
 $5.20
 $0.91
 $1.49
2011            
2014            
Oil — Average sales price ($/bbl) $92.80
 $97.16
 $104.34
 $97.92
 — Average sales price ($/bbl) $84.73
 $88.00
 $96.34
 $90.13
NGLs — Average sales price ($/bbl) $59.10
 $—
 $32.09
 $55.53
 — Average sales price ($/bbl) $37.79
 $—
 $30.98
 $37.01
Gas — Average sales price ($/mcf) $4.06
 $10.11
 $0.81
 $3.01
 — Average sales price ($/mcf) $3.97
 $8.94
 $0.77
 $2.55
(a)Excludes average sales prices from Argentine operations sold in February 2011 and classified as discontinued operations.




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, 20132016, Occidental’s net productive and dry–exploratory and development wells completed.
 United Latin Middle East/   United Latin Middle East/  
  States 
America (a)
 North Africa Total  States America North Africa Total
2013            
2016            
Oil — Exploratory 27.2
 0.8
 3.9
 31.9
 — Exploratory —
 —
 2
 2
   Development 1,161.1
 64.0
 234.6
 1,459.7
   Development 166
 12
 157
 335
Gas — Exploratory 1.0
 —
 0.7
 1.7
 — Exploratory —
 —
 —
 —
   Development 58.3
 2.5
 10.4
 71.2
   Development —
 —
 10
 10
Dry — Exploratory 12.0
 0.8
 2.6
 15.4
 — Exploratory —
 —
 6
 6
   Development 29.9
 1.8
 0.5
 32.2
   Development —
 —
 —
 —
2012            
2015            
Oil — Exploratory 41.0
 —
 3.3
 44.3
 — Exploratory 17
 —
 1
 18
   Development 1,183.8
 51.8
 264.6
 1,500.2
   Development 387
 24
 217
 628
Gas — Exploratory 3.9
 —
 —
 3.9
 — Exploratory —
 —
 2
 2
   Development 134.5
 1.0
 6.5
 142.0
   Development 4
 1
 12
 17
Dry — Exploratory 16.5
 —
 6.1
 22.6
 — Exploratory —
 —
 4
 4
   Development 31.5
 0.4
 2.4
 34.3
   Development —
 1
 1
 2
2011            
2014            
Oil — Exploratory 17.7
 1.8
 2.6
 22.1
 — Exploratory 25
 —
 5
 30
   Development 834.0
 57.9
 189.3
 1,081.2
   Development 419
 52
 253
 724
Gas — Exploratory 3.2
 —
 2.5
 5.7
 — Exploratory 2
 —
 2
 4
   Development 143.1
 —
 1.1
 144.2
   Development 33
 1
 13
 47
Dry — Exploratory 13.0
 —
 1.4
 14.4
 — Exploratory —
 1
 3
 4
   Development 9.3
 —
 1.2
 10.5
   Development —
 1
 —
 1
(a)Excludes for all years presented the exploratory and development wells completed by Argentine operations sold in February 2011 and classified as discontinued operations.



86


Productive Oil and Gas Wells
The following table sets forth, as of December 31, 20132016, Occidental’s productive oil and gas wells (both producing and capable of production).
Wells at
December 31, 2013 (a)
 
United
States
 
Latin
America
 
Middle East/
North Africa
 Total
Wells at
December 31, 2016 (a)
Wells at
December 31, 2016 (a)
 
United
States
 
Latin
America
 Middle East Total
Oil — 
Gross (b)
 28,846
 (1,994) 1,415
 — 3,474
 (729) 33,735
 (2,723) — 
Gross (b)
 16,501
 (841) 1,493
 — 2,209
 (28) 20,203
 (869)
   
Net (c)
 25,334
 (1,490) 703
 — 1,822
 (351) 27,859
 (1,841)   
Net (c)
 14,350
 (773) 748
 — 1,198
 (15) 16,296
 (788)
Gas — 
Gross (b)
 7,508
 (376) 33
 — 149
 (2) 7,690
 (378) — 
Gross (b)
 4,083
 (319) 34
 — 117
 —
 4,234
 (319)
   
Net (c)
 6,754
 (280) 31
 — 77
 (2) 6,862
 (282)   
Net (c)
 3,608
 (298) 31
 — 61
 —
 3,700
 (298)
(a)The numbers in parentheses indicate the number of wells with multiple completions.
(b)The total number of wells in which interests are owned.
(c)The sum of fractional interests.



Participation in Exploratory and Development Wells Being Drilled
The following table sets forth, as of December 31, 20132016, Occidental’s participation in exploratory and development wells being drilled.
Wells at
December 31, 2013
 
United
States
 
Latin
America
 
Middle East/
North Africa
 Total
Wells at
December 31, 2016
Wells at
December 31, 2016
 
United
States
 
Latin
America
 Middle East Total
Exploratory and development wellsExploratory and development wells        Exploratory and development wells        
 — Gross 175
 8
 64
 247
 — Gross 34
 5
 26
 65
 — Net 163
 4
 37
 204
 — Net 32
 4
 16
 52

At December 31, 2013,2016, Occidental was participating in 180109 pressure-maintenance projects, mostly waterfloods, in the United States, 913 in Latin America and 4730 in the Middle East/North Africa.East.


Oil and Gas Acreage
The following table sets forth, as of December 31, 20132016, Occidental’s holdings of developed and undeveloped oil and gas acreage.
Thousands of acres atThousands of acres at United Latin Middle East/  Thousands of acres at United Latin Middle  
December 31, 2013 
States (a)
 America North Africa Total
December 31, 2016December 31, 2016 States America East Total
Developed (b)(a)
Developed (b)(a)
        
Developed (b)(a)
        
 — 
Gross (c)
 8,816
 121
 1,335
 10,272
 — 
Gross (b)
 6,437
 130
 636
 7,203
 — 
Net (d)
 5,307
 83
 607
 5,997
 — 
Net (c)
 2,949
 88
 246
 3,283
Undeveloped (e)(d)
Undeveloped (e)(d)
        
Undeveloped (e)(d)
        
 — 
Gross (c)
 5,723
 368
 6,089
 12,180
 — 
Gross (b)
 1,597
 269
 1,802
 3,668
 — 
Net (d)
 2,906
 248
 4,188
 7,342
 — 
Net (c)
 494
 213
 1,105
 1,812
(a)Includes approximately 2.3 million acres in California, the large majority of which are net fee mineral interests.
(b)Acres spaced or assigned to productive wells.
(c)(b)Total acres in which interests are held.
(d)(c)Sum of the fractional interests owned based on working interests, or interests under PSCs and other economic arrangements.
(e)(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.


87



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, 20132016. 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 2013 2012 2011
United States      
Oil (MBBL)      
California 90
 88
 80
Permian 146
 142
 134
Midcontinent and Other 30
 25
 16
TOTAL 266
 255
 230
NGLs (MBBL)      
California 20
 17
 15
Permian 39
 39
 38
Midcontinent and Other 18
 17
 16
TOTAL 77
 73
 69
Natural gas (MMCF)      
California 260
 256
 260
Permian 157
 155
 157
Midcontinent and Other 371
 410
 365
TOTAL 788
 821
 782
Latin America (a)
      
Oil (MBBL) - Colombia 29
 29
 29
Natural gas (MMCF) - Bolivia 12
 13
 15
Middle East/North Africa      
Oil (MBBL)      
Dolphin 6
 8
 9
Oman 66
 67
 67
Qatar 68
 71
 73
Other 39
 40
 42
TOTAL 179
 186
 191
NGLs (MBBL)      
Dolphin 7
 8
 10
Other —
 1
 —
TOTAL 7
 9
 10
Natural gas (MMCF)      
Dolphin 142
 163
 199
Oman 51
 57
 54
Other 241
 232
 173
TOTAL 434
 452
 426
Total Production (MBOE) (a,b)
 763
 766
 733
(See footnotes following the Sales Volumes per Day table)      


88


Sales Volumes per Day 2013 2012 2011
United States      
Oil (MBBL) 266
 255
 230
NGLs (MBBL) 77
 73
 69
Natural gas (MMCF) 789
 819
 782
Latin America (a)
      
Oil (MBBL) - Colombia 27
 28
 29
Natural gas (MMCF) - Bolivia 12
 13
 15
Middle East/North Africa      
Oil (MBBL)      
Dolphin 6
 8
 9
Oman 68
 66
 69
Qatar 67
 71
 73
Other 38
 40
 38
TOTAL 179
 185
 189
NGLs (MBBL)      
Dolphin 7
 8
 10
Other —
 1
 —
TOTAL 7
 9
 10
Natural gas (MMCF) 434
 452
 426
Total Sales Volumes (MBOE) (a,b)
 762
 764
 731
Production per Day (MBOE) 2016 2015 2014
United States      
Permian Resources 124
 110
 75
Permian EOR 145
 145
 147
South Texas and Other 33
 73
 96
Total 302
 328
 318
Latin America 34
 37
 29
Middle East/North Africa      
Al Hosn 64
 35
 —
Dolphin 43
 41
 38
Oman 96
 89
 76
Qatar 65
 66
 69
Other 26
 72
 67
Total 294
 303
 250
Total Production (MBOE) (a)
 630
 668
 597
(See footnote following the Sales Volumes from Ongoing Operations table)      

Production per Day from Ongoing Operations (MBOE) 2016 2015 2014
United States      
Permian Resources 124
 110
 75
Permian EOR 145
 145
 147
South Texas and Other 31
 42
 52
Total 300
 297
 274
Latin America 34
 37
 29
Middle East      
Al Hosn 64
 35
 —
Dolphin 43
 41
 38
Oman 96
 89
 76
Qatar 65
 66
 69
Total 268
 231
 183
Total Production Ongoing Operations (MBOE) (a)
 602
 565
 486
Sold domestic operations 2
 31
 44
Sold or Exited MENA operations 26
 72
 67
Total Production (MBOE) (a)
 630
 668
 597
(See footnote following the Sales Volumes from Ongoing Operations table)      



Production per Day by Products 2016 2015 2014
United States      
Oil (MBBL)      
Permian Resources 77
 71
 43
Permian EOR 108
 110
 111
South Texas and Other 4
 21
 29
Total 189
 202
 183
NGLs (MBBL)      
Permian Resources 21
 16
 12
Permian EOR 27
 29
 30
South Texas and Other 5
 10
 13
Total 53
 55
 55
Natural gas (MMCF)      
Permian Resources 158
 137
 120
Permian EOR 59
 37
 38
South Texas and Other 144
 250
 318
Total 361
 424
 476
Latin America      
Oil (MBBL) – Colombia 33
 35
 27
Natural gas (MMCF) – Bolivia 8
 10
 11
Middle East/North Africa      
Oil (MBBL)      
Al Hosn 12
 7
 —
Dolphin 7
 7
 7
Oman 77
 82
 69
Qatar 65
 66
 69
Other 7
 32
 28
Total 168
 194
 173
NGLs (MBBL)      
Al Hosn 20
 10
 —
Dolphin 8
 8
 7
Total 28
 18
 7
Natural gas (MMCF)      
Al Hosn 190
 109
 —
Dolphin 166
 158
 143
Oman 115
 44
 43
Other 114
 237
 236
Total 585
 548
 422
Total Production (MBOE) (a)
 630
 668
 597
(See footnote following the Sales Volumes from Ongoing Operations table)      


Production per Day by Products from Ongoing Operations 2016 2015 2014
United States      
Oil (MBBL)      
Permian Resources 77
 71
 43
Permian EOR 108
 110
 111
South Texas and Other 4
 6
 7
Total 189
 187
 161
NGLs (MBBL)      
Permian Resources 21
 16
 12
Permian EOR 27
 29
 30
South Texas and Other 5
 7
 9
Total 53
 52
 51
Natural gas (MMCF)      
Permian Resources 158
 137
 120
Permian EOR 59
 37
 38
South Texas and Other 133
 173
 210
Total 350
 347
 368
Latin America      
Oil (MBBL) – Colombia 33
 35
 27
Natural gas (MMCF) – Bolivia 8
 10
 11
Middle East      
Oil (MBBL)      
Al Hosn 12
 7
 —
Dolphin 7
 7
 7
Oman 77
 82
 69
Qatar 65
 66
 69
Total 161
 162
 145
NGLs (MBBL)      
Al Hosn 20
 10
 —
Dolphin 8
 8
 7
Total 28
 18
 7
Natural gas (MMCF)      
Al Hosn 190
 109
 —
Dolphin 166
 158
 143
Oman 115
 44
 43
Total 471
 311
 186
Total Production Ongoing Operations (MBOE) (a)
 602
 565
 486
Sold domestic operations 2
 31
 44
Sold or Exited MENA operations 26
 72
 67
Total Production (MBOE) (a)
 630
 668
 597
(See footnote following the Sales Volumes from Ongoing Operations table)      



Sales Volumes per Day by Products 2016 2015 2014
United States      
Oil (MBBL) 189
 202
 183
NGLs (MBBL) 53
 55
 55
Natural gas (MMCF) 361
 424
 476
Latin America      
Oil (MBBL) – Colombia 34
 35
 29
Natural gas (MMCF) – Bolivia 8
 10
 11
Middle East/North Africa      
Oil (MBBL)      
Al Hosn 12
 7
 —
Dolphin 7
 8
 7
Oman 77
 82
 69
Qatar 66
 67
 69
 Other 7
 36
 27
Total 169
 200
 172
NGLs (MBBL)      
Al Hosn 20
 10
 —
Dolphin 8
 8
 7
Total 28
 18
 7
Natural gas (MMCF) 585
 548
 422
Total Sales Volumes (MBOE) (a)
 632
 674
 598
(See footnote following the Sales Volumes from Ongoing Operations table)      
Sales Volumes per Day by Products from Ongoing Operations 2016 2015 2014
United States      
Oil (MBBL) 189
 187
 161
NGLs (MBBL) 53
 52
 51
Natural gas (MMCF) 350
 347
 368
Latin America      
Oil (MBBL) – Colombia 34
 35
 29
Natural gas (MMCF) – Bolivia 8
 10
 11
Middle East      
Oil (MBBL)      
Al Hosn 12
 7
 —
Dolphin 7
 8
 7
Oman 77
 82
 69
Qatar 66
 67
 69
Total 162
 164
 145
NGLs (MBBL)      
Al Hosn 20
 10
 —
Dolphin 8
 8
 7
Total 28
 18
 7
Natural gas (MMCF) 471
 311
 186
Total Sales Ongoing Operations (MBOE) (a)
 604
 567
 488
Sold domestic operations 2
 31
 44
Sold or Exited MENA operations 26
 76
 66
Total Sales Volumes (MBOE) (a)
 632
 674
 598
       
(a)For all periods presented, excludes volumes from the Argentine operations sold in February 2011 and classified as discontinued operations.
(b)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 equivalenceequivalence. 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 2013,2016, the average prices of WTI oil and NYMEX natural gas were $97.97$43.32 per barrel and $3.66 per Mcf,$2.42, respectively, resulting in an oil to gas ratio of over 25.18 to 1.


89



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


    Additions     
  Balance at Beginning of Period 
Charged to
Costs and
Expenses
 
Charged to
Other
Accounts
 
Deductions (a)

 
Balance at
End of
Period
 
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) 
2011           
Allowance for doubtful accounts $19
 $—
 $—
 $(3) $16
 
            
Environmental $366
 $53
 $14
 $(73) $360
 
Litigation, tax and other reserves 193
 37
 —
 (32) 198
 
  $559
 $90
 $14
 $(105) $558
(b) 
    Additions     
  Balance at Beginning of Period 
Charged to
Costs and
Expenses
 
Charged to
Other
Accounts
 
Deductions (a)

 
Balance at
End of
Period
 
2016           
Allowance for doubtful accounts $20
 $543
 $(3) $(2) $558
(b) 
          

 
Environmental, litigation, tax and other reserves $479
 $61
 $531
 $(74) $997
(c) 
2015           
Allowance for doubtful accounts $19
 $9
 $(3) $(5) $20
(b) 
            
Environmental, litigation, tax and other reserves $672
 $119
 $2
 $(314) $479
(c) 
2014           
Allowance for doubtful accounts $17
 $4
 $(2) $—
 $19
(b) 
            
Environmental, litigation, tax and other reserves $496
 $80
 $183
 $(87) $672
(c) 
Note:  The amounts presented represent continuing operations.
(a)Primarily represents payments.
(b)Of these amounts, $101$17 million, $20 million and $19 million in 2016, 2015 and 2014, respectively, are classified as current.
(c)Of these amounts, $197 million, $98 million and $100$287 million in 2013, 20122016, 2015 and 2011,2014, respectively, are classified as current.


90



ITEM 9.9CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
Occidental had no changes in, and no disagreements with, Occidental's accountants on accounting and financial disclosure.

ITEM 9A.9ACONTROLS 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, 2016, 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, 2016, 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 ExecutiveSenior 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 ExecutiveSenior Vice President and Chief Financial Officer concluded that Occidental's disclosure controls and procedures were effective as of December 31, 20132016.
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 20132016 that has materially affected, or is reasonably likely to materially affect, Occidental's internal control over financial reporting. Management’s Annual Assessment of and Report on Occidental’s Internal Control over Financial Reporting and theThe Report of Independent Registered Public Accounting Firm on Internal Control over Financial Reporting areis set forth in Item 8.
 
ITEM 9BOTHER INFORMATION
None.



Part IIIIII
ITEM 10.10DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Occidental has adopted a Code of Business Conduct (Code). The Code applies to the President and Chief Executive Officer; ExecutiveSenior Vice President and Chief Financial Officer; Vice President, Controller and Principal Accounting Officer;Officer and Controller; and persons performing similar functions (Key Personnel). The Code also applies to Occidental's directors, its employees and the employees of entities it controls. The Code is posted at www.oxy.com. Occidental will satisfy any disclosure requirement under Item 5.05 of Form 8-K regarding an amendment to, or waiver from, any provision of the Code with respect to its Key Personnel or directors by disclosing the nature of that amendment or waiver on its website.
This item incorporates by reference the information regarding Occidental's directors appearing under the caption "Election of Directors - forepart," and "-Board Committees - Audit Committee," "Security Ownership – Section 16(a) Beneficial Ownership Reporting Compliance," and "General Information – Nominations for Directors for Term Expiring in 2016" in Occidental's definitive Proxy Statement, relating to its May 2, 2014, Annual Meeting of Stockholders (2014 Proxy Statement). The list of Occidental's executive officers and related information under "Executive Officers" set forth in Part I of this report is incorporated by reference herein. The information required by this Item 10 is incorporated herein by reference from Occidental’s definitive Proxy Statement, relating to its May 12, 2017 Annual Meeting of Stockholders, to be filed with the SEC pursuant to Regulation 14A within 120 days of December 31, 2016.

ITEM 11.11EXECUTIVE COMPENSATION
This item incorporates by reference the information appearing under the captions "Compensation Discussion and Analysis," (except "Succession Planning"), "Executive Compensation Tables" and "Director Compensation" in the 2014 Proxy Statement. Pursuant to the rules and regulations under the Exchange Act, theThe 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 12, 2017 Annual Meeting of Stockholders, to be filed with the SEC pursuant to Regulation 14A within 120 days of December 31, 2016.

ITEM 12.12SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
This item incorporatesThe information required by this Item 12 is incorporated herein by reference from Occidental’s definitive Proxy Statement, relating to its May 12, 2017 Annual Meeting of Stockholders, to be filed with the information with respectSEC pursuant to security ownership appearing under the caption "Security Ownership – Certain Beneficial Owners and Management" in the 2014 Proxy Statement. See also the information under "Securities Authorized for Issuance Under Equity Compensation Plans" in Part II, Item 5Regulation 14A within 120 days of this report.December 31, 2016.

ITEM 13.13CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
This item incorporatesThe information required by this Item 13 is incorporated herein by reference from Occidental’s definitive Proxy Statement, relating to its May 12, 2017 Annual Meeting of Stockholders, to be filed with the information appearing under the caption "Corporate Governance – BoardSEC pursuant to Regulation 14A within 120 days of Directors and its Committees – Independence", and " – Other Governance Measures – Related Party Transactions" in the 2014 Proxy Statement.December 31, 2016.

ITEM 14.14PRINCIPAL ACCOUNTANTACCOUNTING FEES AND SERVICES
This item incorporatesThe information required by this Item 14 is incorporated herein by reference from Occidental’s definitive Proxy Statement, relating to its May 12, 2017 Annual Meeting of Stockholders, to be filed with the information with respectSEC pursuant to accountant fees and services appearing under the caption "RatificationRegulation 14A within 120 days of Independent Auditors – Audit and Other Fees" in the 2014 Proxy Statement.December 31, 2016.



91


Part IV
ITEM 15.15EXHIBITS 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, and Certificates of Amendment thereto dated May 5, 2006, May 1, 2009, and May 2, 2014 (filed as Exhibit 3.(i)4.1 to the Annual ReportRegistration Statement on Form 10-KS-8 of Occidental for the fiscal year ended December 31, 1999,dated May 1, 2015, File No. 1-9210)333-203801).
3.(i)(a)*Certificate of Change of Location of Registered Office and of Registered Agent, dated July 6, 2001 (filed as Exhibit 3.1(i) to the Registration Statement on Form S-3 of Occidental, File No. 333-82246).
3.(i)(b)*Certificate of Amendment of Restated Certificate of Incorporation of Occidental Petroleum Corporation, dated May 5, 2006 (filed as Exhibit 3.(i)(b) to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2006, File No. 1-9210).
3.(i)(c)*Certificate of Amendment of Restated Certificate of Incorporation of Occidental Petroleum Corporation, dated May 1, 2009 (filed as Exhibit 3.(i)(c) to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended June 30, 2009, File No. 1-9210).
3.(ii)*Bylaws of Occidental, as amended through May 3, 2013October 8, 2015 (filed as Exhibit 3.(ii) to the Current Report on Form 8-K of Occidental dated May 3, 2013October 8, 2015 (date of earliest event reported), filed May 8, 2013,October 14, 2015, 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 10.7510.55 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*10.1Settlement 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*Petroleum Corporation Savings Plan, Amended and Restated Employment Agreement, dated October 9, 2008, between Occidental and Donald P. de Brier (filed as Exhibit 10.3 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended September 30, 2008, File No. 1-9210).January 1, 2016.
10.4*10.2Amendment to Employment Agreement, dated February 25, 2013, between Occidental Petroleum Corporation Modified Deferred Compensation Plan, Amended and Donald P. de Brier (filedRestated as Exhibit 10.4 to the Annual Report on Form 10-K of January 1, 2017.
10.3Occidental for the fiscal year ended December 31, 2012, File No. 1-9210).Petroleum Corporation Supplemental Retirement Plan II, Amended and Restated as of January 1, 2017.
10.4Occidental Petroleum Corporation Executive Incentive Compensation Plan, Amended and Restated as of January 1, 2016.
10.5*Agreement with Chief Financial Officer (filed as Exhibit 10.7 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended June 30, 2012, File No. 1-9210).
10.6*Retention Payment and Separation Benefits Attachment (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).
10.7*Form of Indemnification Agreement between Occidental and each of its directors and certain executive officers (filed as Exhibit B to the Proxy Statement of Occidental for its May 21, 1987, Annual Meeting of Stockholders, File No. 1-9210).
10.8*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).
10.9*10.7*Split Dollar Life Insurance Agreement, dated January 24, 2002, by and between Occidental and Donald P. de BrierPetroleum Corporation 2015 Long-Term Incentive Plan (filed as Exhibit 10.14.5 to the Quarterly ReportRegistration Statement on Form 10-QS-8 of Occidental, for the quarterly period ended March 31, 2002, File No. 1-9210).

____________________________
* Incorporated herein by reference

92


10.10*Occidental Petroleum Insured Medical Plan, as amended and restated effective April 29, 1994, amending and restating the Occidental Petroleum Corporation Executive Medical Plan (as amended and restated effective April 1, 1993) (filed as Exhibit 10 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ending March 31, 1994, File No. 1-9210)333-203801).
10.11*Form of Occidental Petroleum Corporation Modified Deferred Compensation Plan (Effective December 31, 2006, Amended and Restated Effective November 1, 2008) (filed as Exhibit 10.4 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended September 30, 2008, File No. 1-9210).
10.12*10.8*Form of Occidental Petroleum Corporation Amendment to Senior Executive Supplemental Life Insurance Plan (Effective as of January 1, 1986, Amended and Restated Effective as of January 1, 1996) (filed as Exhibit 10.5 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended September 30, 2008, File No. 1-9210).
10.13*10.9*Form of Occidental Petroleum Corporation Amendment to Senior Executive Survivor Benefit Plan (Effective as of January 1, 1986, Amended and Restated Effective as of January 1, 1996) (filed as Exhibit 10.6 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended September 30, 2008, File No. 1-9210).
10.14*10.10*Form of Occidental Petroleum Corporation Supplemental Retirement Plan II (Effective as of January 1, 2005, AmendedRetention Payment and Restated as of November 1, 2008)Separation Benefits Attachment (filed as Exhibit 10.7 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended September 30, 2008, File No. 1-9210).
10.15*Amendment Number 1 to the Occidental Petroleum Corporation Supplemental Retirement Plan II (Effective As Of January 1, 2005, Amended And Restated As Of November 1, 2008) (filed as Exhibit 10.16 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2009, File No. 1-9210).
10.16*Amendment Number 2 to the Occidental Petroleum Corporation Supplemental Retirement Plan II (Effective As Of January 1, 2005, Amended And Restated As Of November 1, 2008) (filed as Exhibit 10.17 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2009, File No. 1-9210).
10.17*Amendment Number 3 to the Occidental Petroleum Corporation Supplemental Retirement Plan II (Effective As Of January 1, 2005, Amended and Restated as of November 1, 2008) (filed as Exhibit 10.18 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2011, File No. 1-9210).
10.18*Amendment Number 4 to the Occidental Petroleum Corporation Supplemental Retirement Plan II (Effective As Of January 1, 2005, Amended and Restated as of November 1, 2008) (filed as Exhibit 10.19 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2011, File No. 1-9210).
10.19*Amendment Number 5 to the Occidental Petroleum Corporation Supplemental Retirement Plan II (Effective as of January 1, 2005, Amended and Restated as of November 1, 2008) (filed as Exhibit 10.1910.6 to the Annual Report on Form 10-K of Occidental for the fiscal year ended December 31, 2012, File No. 1-9210).
10.20*10.11*First Amendment to the Occidental Petroleum Corporation 2015 Long-Term Incentive Plan (filed as Exhibit 10.1 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended September 30, 2016, File No. 1-9210).
10.12*Form of 2016 Occidental Petroleum Corporation 2015 Long-Term Incentive Plan Common Stock Unit Award For Non-Employee Directors (filed as Exhibit 10.1 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended June 30, 2016, File No. 1-9210).
10.13*Form of 2016 Occidental Petroleum Corporation 2015 Long-Term Incentive Plan Restricted Stock Unit Incentive Award (filed as Exhibit 10.3 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended June 30, 2016, File No. 1-9210).
10.14*Form of 2016 Occidental Petroleum Corporation 2015 Long-Term Incentive Plan Total Shareholder Return Incentive Award (filed as Exhibit 10.4 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended June 30, 2016, File No. 1-9210).
10.15*Occidental Petroleum Corporation 2015 Long-Term Incentive Plan Form of Notice of Grant of Restricted Stock Unit Incentive Award (filed as Exhibit 10.1 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended March 31, 2016, File No. 1-9210).
10.16*Occidental Petroleum Corporation 2001 Incentive Compensation Plan (as amended through September 12, 2002) (filed as Exhibit 10.2 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended September 30, 2002, File No. 1-9210).
10.21*10.17*Terms and Conditions for Incentive Stock Option Award under Occidental Petroleum Corporation 2001 Incentive Compensation Plan (July 2003 version)Letter Agreement relating to Dividend Reinvestments with CEO (filed as Exhibit 10.310.2 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended June 30, 2003,March 31, 2016, File No. 1-9210).
10.22*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).
10.23*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).
10.24*10.18*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).
10.25*10.19*TermsAmended and Conditions of Stock Appreciation Rights Award underRestated Occidental Petroleum Corporation 2005 Long-TermExecutive Incentive Compensation Plan (filed as Exhibit 10.1210.3 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended June 30, 2005,March 31, 2016, File No. 1-9210).
10.26*10.20*AgreementForm of Occidental Petroleum Corporation Modified Deferred Compensation Plan (Effective as of December 31, 2006, Amended and Restated effective as of November 1, 2008 and Restated as of October 31, 2016 solely to Amend Outstanding Option Awards, dated October 26, 2005incorporate all interim amendments) (filed as Exhibit 10.210.3 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended September 30, 2005,2016, File No. 1-9210).
10.27*10.21*Terms and Conditions of Stock Appreciation Rights (SARs) under Occidental Petroleum Corporation 2005 Long-Term Incentive Plan (July 2006 version)Sign-on agreement with General Counsel (filed as Exhibit 10.4 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended June 30, 2006,March 31, 2016, File No. 1-9210).
10.28*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).
10.29*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).
10.30*10.22*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).
10.31*10.23*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).
10.32*Executive Stock Ownership Guidelines (filed as Exhibit 10.1 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended March 31, 2005, File No. 1-9210).
10.33*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).
10.34*Amendment to Form of Restricted Stock Award for Non-Employee Directors under Occidental Petroleum Corporation 2005 Long-Term Incentive Plan (filed as Exhibit 10.3 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended September 30, 2007, File No. 1-9210).

____________________________
* Incorporated herein by reference

9398


10.35*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).
10.36Director Retainer and Attendance Fees.
10.3710.24*Description of Automatic Grant of Directors’ Restricted Stock Awards Pursuant to the Terms of the Occidental Petroleum Corporation 2005 Long-Term Incentive Plan.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).
10.38*10.25*Form of Occidental Petroleum Corporation Supplemental Retirement Plan II (Effective as of January 1, 2005, Long-Term Incentive Plan Occidental OilAmended and Gas Corporation Return on Assets Incentive Award Agreement (Cash-based, Cash-settled Award)Restated as of November 1, 2008 and Restated as of October 31, 2016 solely to incorporate all interim amendments) (filed as Exhibit 10.510.2 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarterquarterly period ended JuneSeptember 30, 2008,2016, File No. 1-9210).
10.39*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).
10.40*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).
10.41*Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Occidental Chemical Corporation Return on Assets Incentive Award Agreement (Cash-based, Cash-settled Award) (filed as Exhibit 10.3 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended June 30, 2009, File No. 1-9210).
10.42*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).
10.43*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).
10.44*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).
10.45*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).
10.46*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).
10.47*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).
10.48*Form of Acknowledgement Letter (filed as Exhibit 10.4 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended June 30, 2011, File No. 1-9210).
10.49*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).
10.50*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).
10.51*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).
10.52*10.26*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).
10.53*10.27*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).
10.54*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).
10.55*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).
10.56*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).
10.57*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).
10.58*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).

____________________________
* Incorporated herein by reference

94


10.59*10.28*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).
10.60*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).
10.61*10.29*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).
10.62*10.30*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).
10.63*10.31*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).
10.64*10.32*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).
10.65*10.33*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).
10.66*10.34*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).
10.67*10.35*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).
10.68*10.36*Occidental Petroleum Corporation AcknowledgementAcknowledgment 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).
10.69*10.37*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).
10.70*10.38*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).
10.71*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).
10.72*10.39*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).
10.73*10.40*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).
10.74*10.41*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).
10.75*10.42*Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Occidental Chemical Corporation Return on Assets IncentiveCommon Stock Unit Award Terms and Conditions (Equity-Based, Equity-Settled Award)For Non-Employee Directors Grant Agreement (filed as Exhibit 10.1510.1 to the Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2014, File No. 1-9210).
10.43*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).
10.44*Form of Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Nonstatutory Stock Option Award Terms and Conditions (filed as Exhibit 10.73 to the Annual Report on Form 10-K for the fiscal year ended December 31, 2014, File No. 1-9210).
10.45*Occidental Petroleum Corporation 2015 Long-Term Incentive Plan Form of Notice of Grant of Restricted Stock Unit Incentive Award (filed as Exhibit 10.4 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended June 30, 2013,2015, File No. 1-9210).
10.46*Occidental Petroleum Corporation 2015 Long-Term Incentive Plan Form of Notice of Grant of Performance Retention Incentive Award (filed as Exhibit 10.5 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended June 30, 2015, File No. 1-9210).
10.47*Occidental Petroleum Corporation 2015 Long-Term Incentive Plan Form of Notice of Grant of Return on Assets Incentive Award (MENA) (filed as Exhibit 10.6 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended June 30, 2015, File No. 1-9210).
10.48*Occidental Petroleum Corporation 2015 Long-Term Incentive Plan Form of Notice of Grant of Return on Assets Incentive Award (Total) (filed as Exhibit 10.7 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended June 30, 2015, File No. 1-9210).
10.49*Occidental Petroleum Corporation 2015 Long-Term Incentive Plan Form of Notice of Grant of Return on Capital Employed Incentive Award (filed as Exhibit 10.8 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended June 30, 2015, File No. 1-9210).

____________________________
* Incorporated herein by reference

99


10.50*Occidental Petroleum Corporation 2015 Long-Term Incentive Plan Form of Notice of Grant of Total Shareholder Return Incentive Award (filed as Exhibit 10.9 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended June 30, 2015, File No. 1-9210).
10.51*Occidental Petroleum Corporation 2015 Long-Term Incentive Plan Notice of Grant of Return on Capital Employed Incentive Award for Stephen I. Chazen (filed as Exhibit 10.10 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended June 30, 2015, File No. 1-9210).
10.52*Occidental Petroleum Corporation 2015 Long-Term Incentive Plan Notice of Grant of Performance Retention Incentive Award for Stephen I. Chazen (filed as Exhibit 10.11 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended June 30, 2015, File No. 1-9210).
10.53*Separation Agreement by and between Occidental Petroleum Corporation and W.C.W (Willie) Chiang, dated June 10, 2015 (filed as Exhibit 10.3 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended June 30, 2015, File No. 1-9210).
10.54*Form of Occidental Petroleum Corporation 2015 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 of Occidental for the fiscal quarter ended June 30, 2015, File No. 1-9210).
10.55*Form of Occidental Petroleum Corporation 2015 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 of Occidental for the fiscal quarter ended June 30, 2015, File No. 1-9210).
10.56*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).
10.57*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).
10.58*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).
10.59*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).
10.60*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).
10.61*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).
12Statement regarding computation of total enterprise ratios of earnings to fixed charges for each of the five years in the period ended December 31, 2013.2016.
21List of subsidiaries of Occidental at December 31, 2013.2016.
23.1Consent of Independent Registered Public Accounting Firm.
23.2Consent of Independent Petroleum Engineers.
31.1Certification of CEO Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2Certification of CFO Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1Certifications of CEO and CFO Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.1Ryder 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, 2013.2016.
101.INSXBRL Instance Document.
101.SCHXBRL Taxonomy Extension Schema Document.
101.CALXBRL Taxonomy Extension Calculation Linkbase Document.
101.LABXBRL Taxonomy Extension Label Linkbase Document.
101.PREXBRL Taxonomy Extension Presentation Linkbase Document.
101.DEFXBRL Taxonomy Extension Definition Linkbase Document.

____________________________
* Incorporated herein by reference

95100


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
   
March 3, 2014By:/s/ Stephen I. ChazenVicki Hollub
  Stephen I. ChazenVicki Hollub
  President and Chief Executive Officer
  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.


   TitleDate
     
 /s/Stephen I. Chazen Vicki Hollub President, Chief Executive OfficerMarch 3, 2014February 23, 2017
 Stephen I. ChazenVicki Hollub Chief Executive Officer and Director
     
 /s/ Cynthia L. WalkerChristopher G. Stavros ExecutiveSenior Vice President andMarch 3, 2014February 23, 2017
 Cynthia L. WalkerChristopher G. Stavros Chief Financial Officer
     
 /s/ Roy PineciJennifer M. Kirk Vice President, Controller andMarch 3, 2014February 23, 2017
 Roy PineciJennifer M. Kirk and Principal Accounting Officer
     
 /s/ Spencer Abraham DirectorMarch 3, 2014February 23, 2017
 Spencer Abraham 
     
 /s/ Howard I. Atkins DirectorMarch 3, 2014February 23, 2017
 Howard I. Atkins 
     
 /s/ Eugene L. Batchelder DirectorChairman of the Board of DirectorsMarch 3, 2014February 23, 2017
 Eugene L. Batchelder 
     
 /s/ Edward P. DjerejianStephen I. Chazen Chairman of the Board of DirectorsDirectorMarch 3, 2014February 23, 2017
 Edward P. DjerejianStephen I. Chazen 
     
 /s/ John E. Feick DirectorMarch 3, 2014February 23, 2017
 John E. Feick 
     
 /s/ Margaret M. Foran DirectorMarch 3, 2014February 23, 2017
 Margaret M. Foran 
     
 /s/ Carlos M. Gutierrez DirectorMarch 3, 2014February 23, 2017
 Carlos M. Gutierrez 
     

96



   TitleDate
     
 /s/ William R. Klesse DirectorMarch 3, 2014February 23, 2017
 William R. Klesse
/s/ Jack B. MooreDirectorFebruary 23, 2017
Jack B. Moore 
     
 /s/ Avedick B. Poladian DirectorMarch 3, 2014February 23, 2017
 Avedick B. Poladian 
     
 /s/ Elisse B. Walter DirectorMarch 3, 2014February 23, 2017
 Elisse B. Walter 











































This report was printed on recycled paper.
© 2014 Occidental Petroleum Corporation

97


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).
10.363.(i)*Director RetainerRestated Certificate of Incorporation of Occidental, dated November 12, 1999, and Attendance Fees.Certificates of Amendment thereto dated May 5, 2006, May 1, 2009, and May 2, 2014 (filed as Exhibit 4.1 to the Registration Statement on Form S-8 of Occidental dated May 1, 2015, File No. 333-203801).
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).
10.373.(ii)*Bylaws of Occidental, as amended through October 8, 2015 (filed as Exhibit 3.(ii) to the Current Report on Form 8-K of Occidental dated October 8, 2015 (date of earliest event reported), filed October 14, 2015, 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 10.55 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.
10.1Occidental Petroleum Corporation Savings Plan, Amended and Restated as of January 1, 2016.
10.2Occidental Petroleum Corporation Modified Deferred Compensation Plan, Amended and Restated as of January 1, 2017.
10.3Occidental Petroleum Corporation Supplemental Retirement Plan II, Amended and Restated as of January 1, 2017.
10.4Occidental Petroleum Corporation Executive Incentive Compensation Plan, Amended and Restated as of January 1, 2016.
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 Corporation 2015 Long-Term Incentive Plan (filed as Exhibit 4.5 to the Registration Statement on Form S-8 of Occidental, File No. 333-203801).
10.8*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).
10.9*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).
10.10*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).
10.11*First Amendment to the Occidental Petroleum Corporation 2015 Long-Term Incentive Plan (filed as Exhibit 10.1 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended September 30, 2016, File No. 1-9210).
10.12*Form of 2016 Occidental Petroleum Corporation 2015 Long-Term Incentive Plan Common Stock Unit Award For Non-Employee Directors (filed as Exhibit 10.1 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended June 30, 2016, File No. 1-9210).
10.13*Form of 2016 Occidental Petroleum Corporation 2015 Long-Term Incentive Plan Restricted Stock Unit Incentive Award (filed as Exhibit 10.3 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended June 30, 2016, File No. 1-9210).
10.14*Form of 2016 Occidental Petroleum Corporation 2015 Long-Term Incentive Plan Total Shareholder Return Incentive Award (filed as Exhibit 10.4 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended June 30, 2016, File No. 1-9210).
10.15*Occidental Petroleum Corporation 2015 Long-Term Incentive Plan Form of Notice of Grant of Restricted Stock Unit Incentive Award (filed as Exhibit 10.1 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended March 31, 2016, File No. 1-9210).
10.16*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).
10.17*Letter Agreement relating to Dividend Reinvestments with CEO (filed as Exhibit 10.2 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended March 31, 2016, File No. 1-9210).
10.18*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).
10.19*Amended and Restated Occidental Petroleum Corporation Executive Incentive Compensation Plan (filed as Exhibit 10.3 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended March 31, 2016, File No. 1-9210).
10.20*Form of Occidental Petroleum Corporation Modified Deferred Compensation Plan (Effective as of December 31, 2006, Amended and Restated effective as of November 1, 2008 and Restated as of October 31, 2016 solely to incorporate all interim amendments) (filed as Exhibit 10.3 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended September 30, 2016, File No. 1-9210).
10.21*Sign-on agreement with General Counsel (filed as Exhibit 10.4 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended March 31, 2016, File No. 1-9210).
10.22*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).
10.23*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).


10.24*Description of Automatic Grant of Directors’ Restricted Stock Awards Pursuant to the Terms of the Occidental Petroleum Corporation 2005 Long-Term Incentive Plan.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).
10.25*Form of Occidental Petroleum Corporation Supplemental Retirement Plan II (Effective as of January 1, 2005, Amended and Restated as of November 1, 2008 and Restated as of October 31, 2016 solely to incorporate all interim amendments) (filed as Exhibit 10.2 to the Quarterly Report on Form 10-Q of Occidental for the quarterly period ended September 30, 2016, File No. 1-9210).
10.26*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).
10.27*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).
10.28*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).
10.29*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).
10.30*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).
10.31*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).
10.32*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).
10.33*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).
10.34*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).
10.35*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).
10.36*Occidental Petroleum Corporation Acknowledgment 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).
10.37*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).
10.38*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).
10.39*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).
10.40*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).
10.41*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).
10.42*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).
10.43*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).
10.44*Form of Occidental Petroleum Corporation 2005 Long-Term Incentive Plan Nonstatutory Stock Option Award Terms and Conditions (filed as Exhibit 10.73 to the Annual Report on Form 10-K for the fiscal year ended December 31, 2014, File No. 1-9210).
10.45*Occidental Petroleum Corporation 2015 Long-Term Incentive Plan Form of Notice of Grant of Restricted Stock Unit Incentive Award (filed as Exhibit 10.4 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended June 30, 2015, File No. 1-9210).
10.46*Occidental Petroleum Corporation 2015 Long-Term Incentive Plan Form of Notice of Grant of Performance Retention Incentive Award (filed as Exhibit 10.5 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended June 30, 2015, File No. 1-9210).
10.47*Occidental Petroleum Corporation 2015 Long-Term Incentive Plan Form of Notice of Grant of Return on Assets Incentive Award (MENA) (filed as Exhibit 10.6 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended June 30, 2015, File No. 1-9210).
10.48*Occidental Petroleum Corporation 2015 Long-Term Incentive Plan Form of Notice of Grant of Return on Assets Incentive Award (Total) (filed as Exhibit 10.7 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended June 30, 2015, File No. 1-9210).
10.49*Occidental Petroleum Corporation 2015 Long-Term Incentive Plan Form of Notice of Grant of Return on Capital Employed Incentive Award (filed as Exhibit 10.8 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended June 30, 2015, File No. 1-9210).
10.50*Occidental Petroleum Corporation 2015 Long-Term Incentive Plan Form of Notice of Grant of Total Shareholder Return Incentive Award (filed as Exhibit 10.9 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended June 30, 2015, File No. 1-9210).
10.51*Occidental Petroleum Corporation 2015 Long-Term Incentive Plan Notice of Grant of Return on Capital Employed Incentive Award for Stephen I. Chazen (filed as Exhibit 10.10 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended June 30, 2015, File No. 1-9210).
10.52*Occidental Petroleum Corporation 2015 Long-Term Incentive Plan Notice of Grant of Performance Retention Incentive Award for Stephen I. Chazen (filed as Exhibit 10.11 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended June 30, 2015, File No. 1-9210).
10.53*Separation Agreement by and between Occidental Petroleum Corporation and W.C.W (Willie) Chiang, dated June 10, 2015 (filed as Exhibit 10.3 to the Quarterly Report on Form 10-Q of Occidental for the fiscal quarter ended June 30, 2015, File No. 1-9210).


10.54*Form of Occidental Petroleum Corporation 2015 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 of Occidental for the fiscal quarter ended June 30, 2015, File No. 1-9210).
10.55*Form of Occidental Petroleum Corporation 2015 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 of Occidental for the fiscal quarter ended June 30, 2015, File No. 1-9210).
10.56*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).
10.57*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).
10.58*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).
10.59*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).
10.60*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).
10.61*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).
12Statement regarding computation of total enterprise ratios of earnings to fixed charges for each of the five years in the period ended December 31, 2013.
2016.
21List of subsidiaries of Occidental at December 31, 2013.
2016.
23.1Consent of Independent Registered Public Accounting Firm.
23.2Consent of Independent Petroleum Engineers.
31.1Certification of CEO Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2Certification of CFO Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1Certifications of CEO and CFO Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.1Ryder 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, 2013.
2016.
101.INSXBRL Instance Document.
101.SCHXBRL Taxonomy Extension Schema Document.
101.CALXBRL Taxonomy Extension Calculation Linkbase Document.
101.LABXBRL Taxonomy Extension Label Linkbase Document.
101.PREXBRL Taxonomy Extension Presentation Linkbase Document.
101.DEFXBRL Taxonomy Extension Definition Linkbase Document.

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* Incorporated herein by reference


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